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                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                    FORM 10-K

[X]               ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001

                                       OR

[ ]             TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                          COMMISSION FILE NO. 0-19279

                        EVERFLOW EASTERN PARTNERS, L.P.
             (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

                DELAWARE                                        34-1659910
     (STATE OR OTHER JURISDICTION OF                         (I.R.S. EMPLOYER
     INCORPORATION OR ORGANIZATION)                         IDENTIFICATION NO.)

          585 WEST MAIN STREET
              P.O. BOX 629
             CANFIELD, OHIO                                        44406
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)                        (ZIP CODE)

        REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 330-533-2692

Securities registered pursuant to Section 12(b) of the Act.

                                                        Name of each exchange
              Title of each class                        on which registered
              -------------------                        -------------------

                                         None

Securities registered pursuant to Section 12(g) of the Act:

                      UNITS OF LIMITED PARTNERSHIP INTEREST

            Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X]     No_______

            Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. _______

            There were 4,509,734 Units of limited partnership interest held by
non-affiliates of the Registrant as of March 20, 2002. The Units generally do
not have any voting rights, but, in certain circumstances, the Units are
entitled to one vote per Unit.

                            Except as otherwise indicated, the information
contained in this Report is as of December 31, 2001.

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                                     PART I
                                     ------


ITEM 1.                 BUSINESS
--------------------------------

INTRODUCTION

           Everflow Eastern Partners, L.P. (the "Company"), a Delaware limited
partnership, engages in the business of oil and gas exploration and development.
The Company was formed for the purpose of consolidating the business and oil and
gas properties of Everflow Eastern, Inc., an Ohio corporation ("EEI"), and the
oil and gas properties owned by certain limited partnerships and working
interest programs managed or operated by EEI (the "Programs"). Everflow
Management Limited, LLC (the "General Partner"), an Ohio limited liability
company, is the general partner of the Company.

           EXCHANGE OFFER. The Company made an offer (the "Exchange Offer") to
acquire the common shares of EEI (the "EEI Shares") and the interests of
investors in the Programs (collectively the "Interests") in exchange for units
of limited partnership interest (the "Units"). The Exchange Offer was made
pursuant to a Registration Statement on Form S-1 declared effective by the
Securities and Exchange Commission on December 19, 1990 (the "Registration
Statement") and the Prospectus dated December 19, 1990, as filed with the
Commission pursuant to Rule 424(b).

           The Exchange Offer terminated on February 15, 1991 and holders of
Interests with an aggregate value (as determined by the Company for purposes of
the Exchange Offer) of $66,996,249 accepted the Exchange Offer and tendered
their Interests. Effective on such date, the Company acquired such Interests,
which included partnership interests and working interests in the Programs, and
all of the outstanding EEI Shares. Of the Interests tendered in the Exchange
Offer, $28,565,244 was represented by the EEI Shares and $38,431,005 by the
remaining Interests.

           The parties who accepted the Exchange Offer and tendered their
Interests received an aggregate of 6,632,464 Units. Everflow Management Company,
a predecessor of the General Partner of the Company, contributed Interests with
an aggregate Exchange Value of $670,980 in exchange for a 1% interest in the
Company.

           THE COMPANY. The Company was organized in September 1990. The
principal executive offices of the Company, the General Partner and EEI are
located at 585 West Main Street, Canfield, Ohio 44406 (telephone number
330-533-2692).

GENERAL

           This Annual Report on Form 10-K contains forward-looking statements
which involve risks and uncertainties. The Company's actual results may differ
significantly from the results discussed in the forward-looking statements. All
statements that address operating



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performance, events or developments that the Company anticipates will occur in
the future, including statements related to future revenue, profits, expenses,
and income or statements expressing general optimism about future results, are
forward-looking statements within the meaning of Section 21E of the Securities
Exchange Act of 1934, as amended ("Exchange Act"). In addition, words such as
"expects," "anticipates," "intends," "plans," "believes," "estimates,"
variations of such words, and similar expressions are intended to identify
forward-looking statements. Forward-looking statements are subject to the safe
harbors created in the Exchange Act.

           Factors that may cause such a difference include, but are not limited
to, the competition with the oil and gas industry, the price of oil and gas in
the Appalachian Basin area, the number of Units tendered pursuant to the
Repurchase Right and the ability to locate productive oil and gas prospects for
development by the Company. The Company undertakes no obligation to update
publicly any forward-looking statements, whether as a result of new information,
future events or otherwise.

DESCRIPTION OF THE BUSINESS

           GENERAL. The Company has participated on an on-going basis in the
acquisition and development of undeveloped oil and gas properties and has
pursued the acquisition of producing oil and gas properties.

           SUBSIDIARIES. The Company has two subsidiaries. EEI was organized as
an Ohio corporation in February 1979 and, since the consummation of the Exchange
Offer, has been a wholly-owned subsidiary of the Company. EEI is engaged in the
business of drilling, developing and operating oil and gas properties and
maintains a leasehold inventory from which the Company selects prospects for
development.

           A-1 Storage of Canfield, Ltd. ("A-1 Storage") was organized as an
Ohio limited liability company in late 1995 and is 99% owned by the Company and
1% owned by EEI. A-1 Storage's business includes leasing of office space to the
Company as well as rental of storage units to non-affiliated parties.

           CURRENT OPERATIONS. The properties of the Company consist in large
part of fractional undivided working interests in properties containing Proved
Reserves of oil and gas located in the Appalachian Basin region of Ohio and
Pennsylvania. Approximately 91% of the estimated total future cash inflows
related to the Company's oil and gas reserves as of December 31, 2001 are
attributable to natural gas reserves. The substantial majority of such
properties are located in Ohio and consist primarily of proved producing
properties with established production histories.

           The Company's operations since February 1991 primarily involve the
production and sale of oil and gas and the drilling and development of 259 (net)
wells. The Company serves as the operator of approximately 76% of the gross
wells and 86% of the net wells which comprise the Company's properties.




                                      -2-
<PAGE>

           The Company expects to hold its producing properties until the oil
and gas reserves underlying such properties are substantially depleted. However,
the Company may from time to time sell any of its producing or other properties
or leasehold interests if the Company believes that such sale would be in its
best interest.

           BUSINESS PLAN. The Company continually evaluates whether the Company
can develop oil and gas properties at historical levels given the current costs
of drilling and development activities, the current prices of oil and gas, and
the Company's experience with regard to finding oil and gas in commercially
productive quantities. The Company has decreased its level of activity in the
development of oil and gas properties compared with historical levels.
Management of the Company has from time to time explored and evaluated the
possible sale of the Company. The Company intends to continue to evaluate this
and other alternatives to maximize value for its Unitholders. See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS."

           ACQUISITION OF PROSPECTS. The Company, through its wholly-owned
subsidiary EEI, maintains a leasehold inventory from which the General Partner
will select oil and gas prospects for development by the Company. EEI makes
additions to such leasehold inventory on an on-going basis. The Company may also
acquire leases from third parties. Prior to 2000, EEI generated approximately
90% of the prospects which were drilled. Beginning in 2000, the Company began
generating fewer prospects and has participated in more joint ventures with
other operators. EEI's current leasehold inventory consists of approximately 32
prospects in various stages of maturity representing approximately 700 net acres
under lease.

           In choosing oil and gas prospects for the Company, the General
Partner does not attempt to manage the risks of drilling through a policy of
selecting diverse prospects in various geographic areas or with the potential of
oil and gas production from different geological formations. Rather,
substantially all prospects are expected to be located in the Appalachian Basin
of Ohio (and, to a lesser extent, Pennsylvania) and to be drilled primarily to
the Clinton/Medina Sands geological formation or closely related oil and gas
formations in such area.

           ACQUISITION OF PRODUCING PROPERTIES. As a potential means of
increasing its reserve base, the Company expects to evaluate opportunities which
it may be presented with to acquire oil and gas producing properties from third
parties in addition to its ongoing leasehold acquisition and development
activities. The Company has acquired a limited amount of producing oil and gas
properties.

           The Company will continue to evaluate properties for acquisition.
Such properties may include, in addition to working interests, royalty
interests, net profit interests and production payments, other forms of direct
or indirect ownership interests in oil and gas production, and properties
associated with the production of oil and gas. The Company also may acquire
general or limited partner interests in general or limited partnerships and
interests in joint ventures, corporations or other entities that have, or are
formed to acquire, explore for or





                                      -3-
<PAGE>

develop, oil and gas or conduct other activities associated with the ownership
of oil and gas production.

           FUNDING FOR ACTIVITIES. The Company finances its current operations,
including undeveloped leasehold acquisition activities, through cash generated
from operations and the proceeds of borrowings. See "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Results of
Operations."

           The Company is permitted to incur indebtedness for any partnership
purpose. It is currently anticipated that any such indebtedness will consist
primarily of borrowings from commercial banks. The Company and EEI have a
revolving credit facility with Bank One, N.A., pursuant to which it had no
borrowings in 2001 and no principal indebtedness was outstanding as of March 20,
2002. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS - Liquidity and Capital Resources."

           Although the Partnership Agreement does not contain any specific
restrictions on borrowings, the Company has no specific plans to borrow for the
acquisition of producing oil and gas properties. The Company expects that
borrowings may be made for the acquisition of undeveloped acreage for future
drilling and development and to fund the Company's costs of drilling and
completing wells. In addition, the Company could borrow funds to enable it to
repurchase any Units tendered in connection with the Repurchase Right. See
"Management's Discussion and Analysis of Financial Condition and results of
operations - Liquidity and Capital Resources."

           The Company has a substantial amount of oil and gas reserves which
have not been pledged as collateral for its existing loans. The Company
generally would not expect to borrow funds, from whatever source, in excess of
40% of its total Proved Reserves (as determined using the Company's Standardized
Measure of Discounted Future Net Cash Flows), although there can be no assurance
that circumstances would not lead to the necessity of borrowings in excess of
this amount. Based upon its current business plan, management has no present
intention to have the Company borrow in excess of this amount. The Company has
estimated Proved and Proved Developed Reserves, determined as of December 31,
2001, which aggregate $45,094,000 (Standardized Measure of Discounted Future Net
Cash Flows) with no bank debt outstanding under the revolving credit facility as
of December 31, 2001.




                                      -4-
<PAGE>



MARKETING

           The ability of the Company to market oil and gas found in and
produced on its properties will depend on many factors beyond its control, the
effect of which cannot be accurately anticipated or predicted. These factors
include, among others, the amount of domestic oil and gas production and foreign
imports available from other sources, the capacity and proximity of pipelines,
governmental regulations, and general market demand.

           OIL. Any oil produced from the properties can be sold at the
prevailing field price to one or more of a number of unaffiliated purchasers in
the area. Generally, purchase contracts for the sale of oil are cancelable on 30
days' notice. The price paid by these purchasers is generally an established or
"posted" price which is offered to all producers. All posted prices in the areas
where the Company's properties are located are generally somewhat lower than the
spot market prices, although there have been substantial fluctuations in crude
oil prices in recent years.

           The price of oil in the Appalachian Basin has ranged from a low of
$8.50 per barrel in December 1998 to a high of $33.25 in September 2000. As of
March 20, 2002, the posted field price in the Appalachian Basin area, the
Company's principal area of operation, was $21.25 per barrel of oil. There can
be no assurance that prices will not be subject to continual fluctuations.
Future oil prices are difficult to predict because of the impact of worldwide
economic trends, supply and demand variables, and such non-economic factors as
the political impact on pricing policies by the Organization of Petroleum
Exporting Countries ("OPEC") and the possibility of supply interruptions. To the
extent the prices that the Company receives for its crude oil production decline
or remain at current levels, the Company's revenues from oil production will be
reduced accordingly.

           Since January 1993, the Company has sold substantially all of its
crude oil production to Ergon Oil Purchasing, Inc.

           NATURAL GAS. The deliverability and price of natural gas is subject
to various factors affecting the supply and demand of natural gas as well as the
effect of federal regulations. Prior to 2000, there had been a surplus of
natural gas available for delivery to pipelines and other purchasers. During
2000, decreases in worldwide energy production capability and increases in
energy consumption brought about a shortage in natural gas supplies. This
resulted in increases in natural gas prices throughout the United States,
including the Appalachian Basin. However, more recently during 2001, lower
energy consumption and increased natural gas supplies have reduced prices to
historical levels. From time to time, especially in summer months, seasonal
restrictions on natural gas production have occurred as a result of distribution
system restrictions. Certain of the Company's wells have been subject to these
limited, seasonal shut-ins and restrictions.

           Over the past ten years, the Company had followed a practice of
selling a significant portion of its natural gas pursuant to Intermediate Term
Adjustable Price Gas Purchase Agreements (the "East Ohio Contracts") with
Dominion Field Services, Inc. and its




                                      -5-
<PAGE>

affiliates ("Dominion") (including The East Ohio Gas Company). Pursuant to the
East Ohio Contracts and subject to certain restrictions and adjustments,
including termination clauses, Dominion was obligated to purchase, and the
Company was obligated to sell, all natural gas production from a specified list
of wells (the "Contract Wells"). Pricing under the East Ohio Contracts was
adjusted annually, up or down, by an amount equal to 80% of the increase or
decrease in Dominion's average Gas Cost Recovery ("GCR") rates.

           The Company's last remaining East Ohio Contract terminated during
2001 and was replaced by short-term contracts, which obligate Dominion to
purchase, and the Company to sell and deliver certain quantities of natural gas
production on a monthly basis throughout the contract periods. A summary of the
Company's gas purchase contracts with Dominion follows:

November 2001 through March 2002

         The first 40,000 MCF per month is priced at $3.51 per MCF.

         The next 50,000 MCF per month is priced at $4.73 per MCF.

         The next 50,000 MCF per month is priced at $5.35 per MCF.

         All gas in excess of 140,000 MCF per month is priced at the NYMEX
         settled price plus $.10 up to the first 250,000 MCF in the aggregate
         during the period.

         All gas in excess of the above volumes is priced at the NYMEX settled
         price plus $.45.

April 2002 through October 2002

         The first 50,000 MCF per month is priced at $4.73 per MCF.

         The next 50,000 MCF per month is priced at $5.35 per MCF.

         The next 20,000 MCF per month is priced at $3.35 per MCF.

         In the event the 250,000 MCF in the November 2001 through March 2002
         period is not met, any remaining balance is priced at the NYMEX settled
         price plus $.10 during the period.

         All gas in excess of the above volumes is priced at the NYMEX settled
         price plus $.45.

November 2002 through October 2003

         The first 20,000 MCF per month is priced at $3.35 per MCF.

         The next 20,000 MCF per month is priced at $4.00 per MCF.





                                      -6-
<PAGE>

         The next 20,000 MCF per month is priced at $4.10 per MCF.

         All gas in excess of the above volumes is priced at NYMEX settled price
         plus $.45.

November 2003 through March 2004

         The first 20,000 MCF per month is priced at $4.05 per MCF.

         Gas in excess of the above volumes has not been committed.

           The Company also has short-term contracts with Interstate Gas Supply,
Inc. ("IGS"), which obligate IGS to purchase, and the Company to sell and
deliver certain quantities of natural gas production on a monthly basis
throughout the contract periods. A summary of the Company's gas purchase
contracts with IGS follows:

November 2001 through October 2002

         The first 50,000 MCF per month is priced at $4.56 per MCF.

         All gas in excess of the above volumes is priced at NYMEX settled price
         plus $.42.

April 2002 through October 2002 and April 2003 through October 2003

         The first 20,000 MCF per month is priced at $3.19 per MCF.

         All gas in excess of the above volumes is priced at the NYMEX settled
         price plus $.27.

November 2002 through March 2003

         The first 20,000 MCF per month is priced at $3.19 per MCF.

         The next 20,000 MCF per month is priced at $4.01 per MCF.

         All gas in excess of the above volumes is priced at the NYMEX settled
         price plus $.57.

November 2003 through March 2004

         The first 20,000 MCF per month is priced at $4.10 per MCF.

         All gas in excess of the above volumes is priced at the NYMEX settled
         price plus $.57.

           As detailed above, the price paid for natural gas purchased by
Dominion and IGS varies based on quantities committed by the Company from time
to time. As of December 31, 2001, natural gas purchased by Dominion covers
production from approximately 420 gross wells, while natural gas purchased by
IGS covers production from approximately 190 gross




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<PAGE>

wells. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS - Inflation and Changes in Prices."

           For the year ended December 31, 2001, with the exception of Dominion
and IGS, which accounted for approximately 50% and 27%, respectively, of the
Company's natural gas sales, no one natural gas purchaser has accounted for more
than 10% of the Company's gas sales. The Company expects that Dominion and IGS
will be the only material natural gas customers for 2002.

SEASONALITY

           During summer months, seasonal restrictions on natural gas production
have occurred as a result of distribution system restrictions. These production
restrictions, and the nature of the Company's business, result in seasonal
fluctuations in the Company's revenue, with the Company receiving more income in
the first and fourth quarters of its fiscal year.

TITLE TO PROPERTIES

           As is customary in the oil and gas industry, the Company performs a
limited investigation as to ownership of leasehold acreage at the time of
acquisition and conducts a title examination and necessary curative work prior
to the commencement of drilling operations on a tract. Title examinations have
been performed for substantially all of the producing oil and gas properties
owned by the Company with regard to (i) substantial tracts of land forming a
portion of such oil and gas properties and (ii) the wellhead location of such
properties. The Company believes that title to its properties is acceptable
although such properties may be subject to royalty, overriding royalty, carried
and other similar interests in contractual arrangements customary in the oil and
gas industry. Also, such properties may be subject to liens incident to
operating agreements and liens for current taxes not yet due, as well as other
comparatively minor encumbrances.

COMPETITION

           The oil and gas industry is highly competitive in all its phases. The
Company will encounter strong competition from major and independent oil
companies in acquiring economically desirable prospects as well as in marketing
production therefrom and obtaining external financing. Major oil and gas
companies, independent concerns, drilling and production purchase programs and
individual producers and operators are active bidders for desirable oil and gas
properties, as well as the equipment and labor required to operate those
properties. Many of the Company's competitors have financial resources,
personnel and facilities substantially greater than those of the Company.

           The availability of a ready market for the oil and gas production of
the Company depends in part on the cost and availability of alternative fuels,
the level of consumer demand, the extent of other domestic production of oil and
gas, the extent of importation of foreign oil and gas, the cost of and proximity
to pipelines and other transportation facilities, regulations by







                                      -8-
<PAGE>

state and federal authorities and the cost of complying with applicable
environmental regulations. The volatility of prices for oil and gas and the
continued oversupply of domestic natural gas have, at times, resulted in a
curtailment in exploration for and development of oil and gas properties.

           There is also extensive competition in the market for gas produced by
the Company. Decreases in worldwide energy production capability and increases
in energy consumption have brought about a shortage in energy supplies recently.
This, in turn, has resulted in substantial competition for markets historically
served by domestic natural gas resources both with alternate sources of energy,
such as residual fuel oil, and among domestic gas suppliers. As a result, at
times there has been volatility in oil and gas prices, widespread curtailment of
gas production and delays in producing and marketing gas after it is discovered.
Changes in government regulations relating to the production, transportation and
marketing of natural gas have also resulted in significant changes in the
historical marketing patterns of the industry. Generally, these changes have
resulted in the abandonment by many pipelines of long-term contracts for the
purchase of natural gas, the development by gas producers of their own marketing
programs to take advantage of new regulations requiring pipelines to transport
gas for regulated fees, and an increasing tendency to rely on short-term sales
contracts priced at spot market prices. See "Marketing" above.

           Gas prices, which were once effectively determined by government
regulations, are now influenced largely by the effects of competition.
Competitors in this market include other producers, gas pipelines and their
affiliated marketing companies, independent marketers, and providers of
alternate energy supplies.

REGULATION OF OIL AND GAS INDUSTRY

           The exploration, production and sale of oil and natural gas are
subject to numerous state and federal laws and regulations. Such laws and
regulations govern a wide variety of matters, including the drilling and spacing
of wells, allowable rates of production, marketing, pricing and protection of
the environment. Such regulations may restrict the rate at which the Company's
wells produce oil and natural gas below the rate at which such wells could
produce in the absence of such regulations. In addition, legislation and
regulations concerning the oil and gas industry are constantly being reviewed
and proposed. Ohio and Pennsylvania, the states in which the Company owns
properties and operates, have statutes and regulations governing a number of the
matters enumerated above. Compliance with the laws and regulations affecting the
oil and gas industry generally increases the Company's costs of doing business
and consequently affects its profitability. Inasmuch as such laws and
regulations are frequently amended or reinterpreted, the Company is unable to
predict the future cost or impact of complying with such regulations.

           The interstate transportation and sale for resale of natural gas is
regulated by the Federal Energy Regulatory Commission (the "FERC") under the
Natural Gas Act of 1938 ("NGA"). The wellhead price of natural gas is also
regulated by FERC under the authority of the Natural Gas Policy Act of 1978
("NGPA"). Subsequently, the Natural Gas Wellhead Decontrol







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Act of 1989 (the "Decontrol Act") was enacted on July 26, 1989. The Decontrol
Act provided for the phasing out of price regulation under the NGPA commencing
on the date of enactment and completely eliminated all such gas price regulation
on January 1, 1993. In addition, FERC recently has adopted and proposed several
rules or orders concerning transportation and marketing of natural gas. The
impact of these rules and other regulatory developments on the Company cannot be
predicted. It is expected that the Company will sell natural gas produced by its
oil and gas properties to a number of purchasers, including various industrial
customers, pipeline companies and local public utilities, although the majority
will be sold to East Ohio as discussed earlier.

           As a result of the NGPA and the Decontrol Act, the Company's gas
production is no longer subject to price regulation. Gas which has been removed
from price regulation is subject only to that price contractually agreed upon
between the producer and purchaser. Under current market conditions, deregulated
gas prices under new contracts tend to be substantially lower than most
regulated price ceilings originally prescribed by the NGPA. FERC recently has
proposed and enacted several rules or orders concerning transportation and
marketing of natural gas. In 1992, the FERC finalized Order 636, a rule
pertaining to the restructuring of interstate pipeline services. This rule
requires interstate pipelines to unbundle transportation and sales services by
separately pricing the various components of their services, such as supply,
gathering, transportation and sales. These pipeline companies are required to
provide customers only the specific service desired without regard to the source
for the purchase of the gas. Although the Partnership is not an interstate
pipeline, it is likely that this regulation may indirectly impact the
Partnership by increasing competition in the marketing of natural gas, possibly
resulting in an erosion of the premium price historically available for
Appalachian natural gas. The impact of these rules and other regulatory
developments on the Company cannot be predicted.

           Regulation of the production, transportation and sale of oil and gas
by federal and state agencies has a significant effect on the Company and its
operating results. Certain states, including Ohio and Pennsylvania, have
established rules and regulations requiring permits for drilling operations,
drilling bonds and reports concerning the spacing of wells.

ENVIRONMENTAL REGULATION

           The activities of the Company are subject to various federal, state
and local laws and regulations designed to protect the environment. The Company
does not conduct activities offshore. Operations of the Company on onshore oil
properties may generally be liable for clean-up costs to the federal government
under the Federal Clean Water Act for up to $50,000,000 for each incident of oil
or hazardous pollution substance and for up to $50,000,000 plus response costs
under the Comprehensive Environmental Response, Compensation, and Liability Act
of 1980 ("Superfund") for hazardous substance contamination. Liability is
unlimited in cases of willful negligence or misconduct, and there is no limit on
liability for environmental clean-up costs or damages with respect to claims by
the state or private persons or entities. In addition, the Company is required
by the Environmental Protection Agency ("EPA") to prepare and implement spill
prevention control and countermeasure plans relating to the







                                      -10-
<PAGE>

possible discharge of oil into navigable waters; and the EPA will further
require permits to authorize the discharge of pollutants into navigable waters.
State and local permits or approvals may also be needed with respect to
waste-water discharges and air pollutant emissions. Violations of
environment-related lease conditions or environmental permits can result in
substantial civil and criminal penalties as well as potential court injunctions
curtailing operations. Such enforcement liabilities can result from prosecution
by public or private entities.

           Various state and governmental agencies are considering, and some
have adopted, other laws and regulations regarding environmental protection
which could adversely affect the proposed business activities of the Company.
The Company cannot predict what effect, if any, current and future regulations
may have on the operations of the Company.

           In addition, from time to time, prices for either oil or natural gas
have been regulated by the federal government, and such price regulation could
be reimposed at any time in the future.

OPERATING HAZARDS AND UNINSURED RISKS

           The Company's oil and gas operations are subject to all operating
hazards and risks normally incident to drilling for and producing oil and gas,
such as encountering unusual formations and pressures, blow-outs, environmental
pollution and personal injury. The Company maintains such insurance coverage as
it believes to be appropriate taking into account the size of the Company and
its operations. Losses can occur from an uninsurable risk or in amounts in
excess of existing insurance coverage. The occurrence of an event which is not
insured or not fully insured could have an adverse impact on the Company's
revenues and earnings.

           In certain instances, the Company may continue to engage in
exploration and development operations through drilling programs formed with
non-industry investors. In addition, the Company also will conduct a significant
portion of its operations with other parties in connection with the drilling
operations conducted on properties in which it has an interest. In these
arrangements, all joint interest parties, including the Company, may be fully
liable for their proportionate share of all costs of such operations. Further,
if any joint interest party defaults on its obligations to pay its share of
costs, the other joint interest parties may be required to fund the deficiency
until, if ever, it can be collected from the defaulting party. As a result of
the foregoing or similar oilfield circumstances, the Company could become liable
for amounts significantly in excess of amounts originally anticipated to be
expended in connection with such operations. In addition, financial difficulty
for an operator of oil and gas properties could result in the Company's and
other joint interest owners' interests in properties and the wells and equipment
located thereon becoming subject to liens and claims of creditors,
notwithstanding the fact that non-defaulting joint interest owners and the
Company may have previously paid to the operator the amounts necessary to pay
their share of such costs and expenses.




                                      -11-
<PAGE>



CONFLICTS OF INTEREST

           The Partnership Agreement grants the General Partner broad
discretionary authority to make decisions on matters such as the Company's
acquisition of or participation in a drilling prospect or a producing property.
To limit the General Partner's management discretion might prevent it from
managing the Company properly. However, because the business activities of the
affiliates of the General Partner on the one hand and the Company on the other
hand are the same, potential conflicts of interest are likely to exist, and it
is not possible to completely mitigate such conflicts.

           The Partnership Agreement contains certain restrictions designed to
mitigate, to the extent practicable, these conflicts of interest. The agreement
restricts, among other things, (i) the cost at which the General Partner or its
affiliates may acquire properties from or sell properties to the Company; (ii)
loans between the General Partner, its affiliates and the Company, and interest
and other charges incurred in connection therewith; and (iii) the use and
handling of the Company's funds by the General Partner.

EMPLOYEES

           As of March 20, 2002, the Company (either directly or indirectly
through EEI) had 16 full-time and two part-time employees. These employees
primarily are engaged in the following areas of business operations: two in land
and lease acquisition, five in field operations, five in accounting, and six in
administration.






























                                      -12-
<PAGE>



ITEM 2.    PROPERTIES.
----------------------

           Set forth below is certain information regarding the oil and gas
properties of the Company.

           In the following discussion, "gross" refers to the total acres or
wells in which the Company has a working interest and "net" refers to gross
acres or wells multiplied by the Company's percentage of working interests
therein. Because royalty interests held by the Company will not affect the
Company's working interests in its properties, neither gross nor net acres or
wells reflect such royalty interests.

           PROVED RESERVES.(1) The following table reflects the estimates of the
Company's Proved Reserves which are based on the Company's report as of December
31, 2001.

                                              OIL (BBLS)            GAS (MCF)
                                              ----------            ---------
           Proved Developed                      719,000           41,925,000
           Proved Undeveloped                       --                   --
                                              ----------           ----------
           Total                                 719,000           41,925,000
                                               ==========           ==========

           -------------------------
           (1)        The Company has not determined proved reserves associated
                      with its proved undeveloped acreage. A reconciliation of
                      the Company's proved reserves is included in the Notes to
                      the Financial Statements.

           STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS.(1) The
following table summarizes, as of December 31, 2001, the oil and gas reserves
attributable to the oil and gas properties owned by the Company. The
determination of the standardized measure of discounted future net cash flows as
set forth herein is based on criteria promulgated by the Securities and Exchange
Commission, using calculations based solely on Proved Reserves, current
unescalated cost and price factors, and discounted to present value at 10%.

                                                                    (THOUSANDS)
                                                                     ---------

           Future cash inflows from sales of oil and gas             $138,032
           Future production and development costs                     57,159
           Future income tax expense                                    1,675
                                                                     --------

           Future net cash flows                                       79,198
           Effect of discounting future net cash flows
                 at 10% per annum                                      34,104
                                                                     --------
           Standardized measure of discounted future
                 net cash flows                                      $ 45,094
                                                                     ========

           ---------------------------------
           (1)        See the Notes to the Financial Statements for additional
                      information.






                                      -13-
<PAGE>

           PRODUCTION. The following table summarizes the net oil and gas
production, average sales prices and average production (lifting) costs per
equivalent unit of production for the periods indicated.

<TABLE>
<CAPTION>
                                                                        Average
                                 Production                           Sales Price
                     ----------------------------------     ----------------------------     Average Lifting Cost
                     Oil (BBLS)               Gas (MCF)     per BBL              per MCF      per Equivalent MCF(1)
                     ----------               ---------     -------              -------      ------------------

      <S>            <C>                     <C>            <C>                 <C>              <C>
      2001            76,000                  3,583,000     $ 22.57              $ 3.93              $ .60
      2000            92,000                  4,196,000       27.82                3.32                .47
      1999            97,000                  4,245,000       16.08                3.08                .55
</TABLE>

      ----------------------
      (1)      Oil production is converted to MCF equivalents at the rate of
               6 MCF per BBL (barrel).


           PRODUCTIVE WELLS. The following table sets forth the gross and net
oil and gas wells of the Company as of December 31, 2001.
<TABLE>
<CAPTION>

                       GROSS WELLS                                      NET WELLS
            --------------------------------------------------------------------------------------------
                   (1)            (1)                              (1)             (1)
                Oil             Gas             Total           Oil             Gas             Total
            --------------------------------------------------------------------------------------------
<S>             <C>             <C>             <C>             <C>             <C>              <C>
                80              946             1,026           56              667              723
</TABLE>

               ----------------------------
               (1)      Oil wells are those wells which generate the majority
                        of their revenues from oil production; gas wells are
                        those wells which generate the majority of their
                        revenues from gas production.


           ACREAGE. The Company had 45,207 gross developed acres and 32,310 net
developed acres as of December 31, 2001. Developed acreage is that acreage
assignable to productive wells. The Company had approximately 700 gross and net
undeveloped acres as of December 31, 2001.













                                      -14-
<PAGE>




           DRILLING ACTIVITY. The following table sets forth the results of
drilling activities on properties owned by the Company. Such information and the
results of prior drilling activities should not be considered as necessarily
indicative of future performance.
<TABLE>
<CAPTION>

                                                                            Development Wells(1)
                                          -----------------------------------------------------------------------------
                                                         Productive                                 Dry
                                          ----------------------------------         ----------------------------------
                                                Gross               Net                    Gross               Net
                                          ---------------    ---------------         ---------------    ---------------

<S>                        <C>                   <C>             <C>                         <C>                <C>
                           2001                  33              15.14                       -                  -
                           2000                  26              11.28                       1                 .14
                           1999                  22              12.40                       2                 .20
</TABLE>
                           ----------------------
                           (1)      All wells are located in the United States.
                                    All wells are development wells; no
                                    exploratory wells were drilled.


           PRESENT ACTIVITIES. The Company has drilled 4 gross and 1.64 net
development wells since December 31, 2001. As of March 20, 2002, the Company had
2 gross and 0.70 net wells in the process of being drilled.

           DELIVERY COMMITMENTS. The Company entered into various contracts with
Dominion and IGS which, subject to certain restrictions and adjustments,
obligate Dominion and IGS to purchase and the Company to sell all natural gas
production from certain contract wells. The contract wells comprise more than
75% of the Company's natural gas sales. In addition, the Company has entered
into various short-term contracts which obligate the purchasers to purchase and
the Company to sell and deliver certain quantities of natural gas production on
a monthly basis throughout the term of the contracts.

ITEM 3.    LEGAL PROCEEDINGS
----------------------------

           There are no material pending legal proceedings to which the Company
is a party or to which any of its property is subject.

ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
--------------------------------------------------------------

           During the fourth quarter of the fiscal year ended December 31, 2001,
there were no matters submitted to a vote of security holders through the
solicitation of proxies or otherwise.





                                      -15-
<PAGE>




                                     PART II
                                     -------


ITEM 5.    MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
----------------------------------------------------------------------------
            MATTERS
MARKET     --------

           There is currently no established public trading market for the
Units. At the present time, the Company does not intend to list any of the Units
for trading on any exchange or otherwise take any action to establish any market
for the Units. As of March 20, 2002, there were 5,771,174 Units held by 1,443
holders of record.

DISTRIBUTION HISTORY.
--------------------

           The Company commenced operations with the consummation of the
Exchange Offer in February 1991. Management's stated intention was to make
quarterly cash distributions equal to $0.125 per Unit (or $0.50 per Unit on an
annualized basis) for the first eight quarters following the closing date of the
Exchange Offer. The Company has paid a quarterly distribution every quarter
since July 1991. Based upon the current number of Units outstanding, each
quarterly distribution of $0.125 per Unit would be approximately $730,000. The
Company made a quarterly distribution of $0.25 per Unit in January 2002 and
currently intends to make a quarterly distribution of $0.25 per Unit in April
2002 and quarterly distributions of at least $0.125 per Unit in July and October
2002.

REPURCHASE RIGHT.
----------------

           The Partnership Agreement provides, that beginning in 1992 and
annually thereafter, the Company will repurchase for cash up to 10% of the then
outstanding Units, to the extent Unitholders offer Units to the Company for
repurchase (the "Repurchase Right"). The Repurchase Right entitles any
Unitholder, between May 1 and June 30 of each year, to notify the Company that
he elects to exercise the Repurchase Right and have the Company acquire certain
or all of his Units. The price to be paid for any such Units is calculated based
on the method provided for in the Partnership Agreement. The Company accepted an
aggregate of 77,344, 206,531 and 117,488 of its Units of limited partnership
interest at a price of $5.79, $6.11 and $9.73 per Unit pursuant to the terms of
the Company's Offers to Purchase dated April 30, 1999, 2000 and 2001,
respectively. See Note 4 in the Company's financial statement for additional
information on the Repurchase Right.




                                      -16-
<PAGE>




ITEM 6.                 SELECTED FINANCIAL DATA
-----------------------------------------------
<TABLE>
<CAPTION>

                                                                      YEAR ENDED DECEMBER 31,
                                             ---------------------------------------------------------------------

                                                 2001           2000          1999           1998          1997
                                             ---------------------------------------------------------------------

<S>                                           <C>           <C>           <C>           <C>           <C>
Revenue ...................................   $16,261,220   $16,921,139   $15,063,170   $16,558,366   $15,932,197
Net Income ................................     7,842,162     8,590,757     5,445,941     6,897,089     5,696,407
Net Income Per Unit .......................          1.33          1.42           .88          1.10           .90
Total Assets ..............................    52,254,265    55,043,294    55,422,986    56,612,953    54,760,106
Debt(1) ...................................       512,014       637,822       692,289     2,255,898     4,589,143
Cash Distributions Per Unit ...............          1.50          1.25          .625           .50           .50
</TABLE>
------------------------------
(1)        Debt includes the Company's long-term debt and borrowings under the
           Company's revolving credit facility.



ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
--------------------------------------------------------------------------
           RESULTS OF OPERATIONS
           ---------------------

GENERAL

           The Company was organized in September 1990 as a limited partnership
under the laws of the State of Delaware. Everflow Management Limited, LLC, an
Ohio limited liability company, is the general partner of the Company. The
Company was formed to engage in the business of oil and gas exploration and
development through a proposed consolidation of the business and oil and gas
properties of EEI, and the oil and gas properties owned by certain limited
partnerships and working interest programs managed or operated by the Programs.

           Effective February 15, 1991, pursuant to the Exchange Offer to
acquire the EEI shares and the Interests in exchange for Units of the Company's
limited partnership interest, the Company acquired the Interests and the EEI
Shares and EEI became a wholly-owned subsidiary of the Company.

           The General Partner is a limited liability company. The members of
the General Partner are EMC, two individuals who are currently directors and/or
officers of EEI, Thomas L. Korner and William A. Siskovic, and Sykes Associates,
a limited partnership controlled by Robert F. Sykes, the Chairman of the Board
of EEI.

LIQUIDITY AND CAPITAL RESOURCES

FINANCIAL POSITION

           Working capital surplus of $7.0 million as of December 31, 2001
represented a $1.0 million decrease from December 31, 2000 due primarily to
decreases in cash and equivalents of $869 thousand and accounts receivable from
oil and gas production of $603



                                      -17-
<PAGE>

thousand during 2001. These were partially offset by a decrease in accounts
payable of $514 thousand. In August 2001, the Company entered into an agreement
that modified its prior credit agreement. The agreement provides for a revolving
line of credit in the amount of $4,000,000, all of which is available. The
revolving line of credit provides for interest payable quarterly at LIBOR plus
150 basis points with the principal due at maturity, May 31, 2003. The Company
anticipates renewing the facility on an every other year basis to minimize debt
origination, carrying and interest costs associated with long-term bank
commitments. The Company made no borrowings under the revolving credit
facilities during 2001. Cash flows were used to pay for the funding of the
Company's investment in and the continued development of oil and gas properties
and to repurchase Units pursuant to the Repurchase Right. The Company
repurchased 117,488 Units at a price of $9.73 per Unit, or $1,143,158, on June
30, 2001. The Company also used cash flows to make quarterly Cash Distributions,
which totaled $8.8 million.

           The following table summarizes the Company's financial position at
December 31, 2001 and December 31, 2000:
<TABLE>
<CAPTION>

            (Amounts in Thousands)                                   DECEMBER 31, 2001             DECEMBER 31, 2000
                                                                   ---------------------        ---------------------
                                                                    AMOUNT          %            AMOUNT          %
                                                                   -------       -------        -------       -------

<S>                                                                <C>                <C>       <C>                <C>
              Working capital                                      $ 6,985            14%       $ 7,931            15%
              Property and equipment (net)                          44,325            86         45,639            85
              Other                                                    110          --              103          --
                                                                   -------       -------        -------       -------
                    Total                                          $51,420           100%       $53,673           100%
                                                                   =======       =======        =======       =======

              Long-term debt                                       $   458             1%       $   579             1%
              Deferred income taxes                                     50          --               50          --
              Partners' equity                                      50,912            99         53,044            99
                                                                   -------       -------        -------       -------
                    Total                                          $51,420           100%       $53,673           100%
                                                                   =======       =======        =======       =======
</TABLE>

CASH FLOWS FROM OPERATING, INVESTING AND FINANCING ACTIVITIES

           The Company generated almost all of its cash sources from operating
activities. During the years ended 2001 and 2000, cash provided by operations
was used to fund the development of additional oil and gas properties,
repurchase of Units pursuant to the Repurchase Right and distributions to
partners.








                                      -18-
<PAGE>




                        The following table summarizes the Company's Statements
of Cash Flows for the years ended December 31, 2001 and 2000:

<TABLE>
<CAPTION>
(Amounts in Thousands)                                        2001                        2000
                                                   ---------------------------------------------------
                                                    DOLLARS          %          DOLLARS            %
                                                   ---------------------------------------------------
<S>                                                <C>                 <C>      <C>                 <C>
Operating Activities:
      Net income before adjustments                $  7,842            59%      $  8,591            60%
      Adjustments                                     4,709            35          4,968            35
                                                   --------      --------       --------      --------
      Cash flow from operations
         before working capital
         changes                                     12,551            94         13,559            95
      Changes in working capital                        (77)           (1)        (2,818)          (20)
                                                   --------      --------       --------      --------
      Net cash provided by
         operating activities                        12,474            93         10,741            75

Investing Activities:
      Proceeds received on receivables
         from officers and employees                    274             2            249             2
      Advances disbursed to officers
         and employees                                 (122)           (1)          (130)           (1)
      Purchase of property and
         equipment                                   (3,395)          (25)        (2,594)          (18)
      Purchase of other assets                         --            --              (64)         --
      Proceeds on sale of other assets
         and equipment                                 --            --                1          --
                                                   --------      --------       --------      --------
      Net cash (used) by investing
         activities                                  (3,243)          (24)        (2,538)          (18)

Financing Activities:
      Distributions                                  (8,831)          (66)        (7,574)          (53)
      Repurchase of Units                            (1,143)           (8)        (1,262)           (9)
      Debt proceeds                                    --            --             --            --
      Debt repayments                                  (126)           (1)           (54)         --
                                                   --------      --------       --------      --------
      Net cash (used) by financing
         activities                                 (10,100)          (75)        (8,890)          (62)
                                                   --------      --------       --------      --------

Increase (decrease) in cash
      and equivalents                                  (869)           (6)          (687)           (5)
</TABLE>

Note:       All items in the previous table are calculated as a percentage of
            total cash sources. Total cash sources include the following items,
            if positive: cash flow from operations before working capital
            changes, changes in working capital, net cash provided by investing
            activities and net cash provided by financing activities, plus any
            decrease in cash and cash equivalents.





                                      -19-
<PAGE>

           As the above table indicates, the Company's cash flow from operations
before working capital changes during the twelve months of 2001 and 2000
represented 94% and 95% of total cash sources, respectively. Changes in working
capital other than cash and equivalents decreased cash by $77 thousand and
$2,818 thousand during 2001 and 2000, respectively. The decrease in accounts
receivable at December 31, 2001 compared to December 31, 2000 is the result of
lower production volumes. Total production revenues receivable as of December
31, 2001 amounted to $2.5 million compared to $3.1 million at December 31, 2000.
Due to lower production volumes, accounts payable relating to production as of
December 31, 2001 was also lower. Accounts payable amounted to $505 thousand as
of December 31, 2001 compared to $1,019 thousand at December 31, 2000. The
Company had investments in short-term marketable corporate debt securities of
$3.8 million and $3.6 million at December 31, 2001 and 2000, respectively.

           The Company's cash flows used by investing activities increased $706
thousand, or 28%, during 2001 as compared with 2000. The Company's cash flows
used by investing activities decreased $464 thousand, or 15%, during 2000 as
compared with 1999. The primary reason for the increase in cash flows used by
investing activities in 2001 was an increase in the purchase of property and
equipment. The purchase of property and equipment increased $801 thousand, or
31%, during 2001 as compared with 2000. The purchase of property and equipment
decreased $821 thousand, or 24%, during 2000 as compared with 1999.

           The Company's cash flows used by financing activities increased
$1,210 thousand, or 14%, during 2001 as compared with 2000. The primary reason
for this increase was that distributions to Unitholders increased $1,257
thousand. Payments on debt increased $71 thousand to $126 thousand during 2001.
The Company's cash flows used by financing activities increased $2,998 thousand,
or 51%, during 2000 as compared with 1999. The primary reason for this increase
was that distributions to Unitholders increased $3,693 thousand. Proceeds from
the issuance of debt decreased $2,175 thousand and payments on debt decreased
$3,684 thousand to $54 thousand during 2000. Additionallly, payments on the
repurchase of Units increased $814 thousand, or 182%, during 2000 as compared
with 1999.

           The Company's ending cash and equivalents balance of $1.1 million and
short-term investments balance of $3.8 million at December 31, 2001, as well as
on-going monthly operating cash flows, should be adequate to meet short-term
cash requirements. The Company has established a quarterly distribution and
management believes the payment of such distributions will continue at least
through 2002. The Company has paid a quarterly distribution every quarter since
July 1991. Minimum cash distributions are estimated to be $730 thousand per
quarter ($.125 per Unit). The Company intends to distribute $1.5 million ($.25
per Unit) in April 2002 using the proceeds from its investments in marketable
corporate debt securities.

           Capital expenditures for the development of oil and gas properties in
the Company and the acquisition of undeveloped leasehold acreage have decreased
compared with historical levels. The Company drilled or participated in the
drilling of an additional 33 drillsites in 2001. The Company's share of these
drillsites amounts to 15.14 net developed properties. The Company's share of
proved gas reserves decreased by 6.6 million MCFs, or 14%, between




                                      -20-
<PAGE>

December 31, 2000 and 2001, while proved oil reserves decreased by 195 thousand
barrels, or 21%, between December 31, 2000 and 2001. The Company continues to
develop primarily natural gas fields, as represented by the discovery and
addition of 1.9 million MCFs of natural gas versus 35 thousand barrels of crude
oil during 2001. The Standardized Measure of Discounted Future Net Cash Flows of
the Company's reserves decreased by $36.9 million between December 31, 2000 and
2001. The primary reason for this decrease was due to decreases in natural gas
and crude oil prices between December 31, 2000 and 2001. Management believes the
Company should be able to drill or participate in the drilling of 7 to 15 net
wells each year for the next few years.

           The Partnership Agreement provides that the Company annually offers
to repurchase for cash up to 10% of the then outstanding Units, to the extent
Unitholders offer Units to the Company for repurchase pursuant to the Repurchase
Right. The Repurchase Right entitles any Unitholder, between May 1 and June 30
of each year, to notify the Company of his or her election to exercise the
Repurchase Right and have the Company acquire such Units. The price to be paid
for any such Units will be calculated based upon the audited financial
statements of the Company as of December 31 of the year prior to the year in
which the Repurchase Right is to be effective and independently prepared reserve
reports. The price per Unit will be equal to 66% of the adjusted book value of
the Company allocable to the Units, divided by the number of Units outstanding
at the beginning of the year in which the applicable Repurchase Right is to be
effective less all Interim Cash Distributions received by a Unitholder. The
adjusted book value is calculated by adding partner's equity, the Standardized
Measure of Discounted Future Net Cash Flows and the tax effect included in the
Standardized Measure and subtracting from that sum the carrying value of oil and
gas properties (net of undeveloped lease costs). If more than 10% of the then
outstanding Units are tendered during any period during which the Repurchase
Right is to be effective, the Investor's Units so tendered shall be prorated for
purposes of calculating the actual number of Units to be acquired during any
such period. The Company repurchased 117,488, 206,531 and 77,344 Units during
2001, 2000 and 1999 pursuant to the Repurchase Right at a price of $9.73, $6.11
and $5.79 per Unit, respectively. The Company has, in the past, borrowed against
its credit facility to meet such obligations and could do so again in 2002,
although current cash flows would reduce borrowing requirements. The Repurchase
Right to be conducted in 2002 will result in Unitholders being offered a price
of $5.66 per Unit. The Company estimates it could need to borrow up to $3.3
million in the event the 2002 offering pursuant to the Repurchase Right is fully
subscribed.


RESULTS OF OPERATIONS

           The following table and discussion is a review of the results of
operations of the Company for the years ended December 31, 2001, 2000 and 1999.
All items in the table are calculated as a percentage of total revenues. This
table should be read in conjunction with the discussions of each item below:



                                      -21-
<PAGE>


<TABLE>
<CAPTION>

                                                                            YEAR ENDED DECEMBER 31,
                                                                      ----------------------------------
                                                                       2001          2000          1999
                                                                      ------        ------        ------
<S>                                                                       <C>           <C>           <C>
Revenues:
      Oil and gas sales                                                   97%           97%           97%
      Well management and operating                                        3             3             3
                                                                      ------        ------        ------
            Total Revenues                                               100           100           100
Expenses:
      Production costs                                                    15            13            18
      Well management and operating                                        1             1             1
      Depreciation, depletion and amortization                            28            27            32
      Abandonment and write down
            of oil and gas properties                                      1             2             4
      General and administrative                                           8             8            11
      Other expense (income)                                              (1)           (2)           (1)
      Income taxes                                                      --            --              (1)
                                                                      ------        ------        ------
            Total Expenses                                                52            49            64
                                                                      ------        ------        ------
Net income                                                                48%           51%           36%
                                                                      ======        ======        ======
</TABLE>


           Revenues for the year ended December 31, 2001 decreased $686
thousand, or 4%, compared to the same period in 2000. Revenues for the year
ended December 31, 2000 increased $1,858 thousand, or 12%, compared to the same
period in 1999. These changes were due primarily to changes in crude oil and
natural gas sales between the periods involved.

           Oil and gas sales decreased $660 thousand, or 4%, from 2000 to 2001.
The primary reason for this decrease was the result of lower natural gas
production and lower crude oil production and oil prices. The Company's gas
production decreased by 613 thousand MCF. The primary reason for this decrease
was due to declining production from the Company's existing oil and gas
properties caused by numerous events including production restrictions resulting
from a warmer than usual fourth quarter in the Appalachian Basin. The average
price received per MCF increased from $3.32 to $3.93 from 2000 to 2001. Oil
sales were lower due primarily to a decrease in the average sales price of oil
from $27.82 to $22.57 per barrel from 2000 to 2001. Additionally, oil production
decreased by 16 thousand barrels. Gas sales accounted for 89%, 84% and 89% of
total oil and gas sales in 2001, 2000 and 1999, respectively. Oil and gas sales
increased $1.9 million, or 13%, from 1999 to 2000. The primary reason for this
increase in oil and gas sales between 1999 and 2000 was higher natural gas and
crude oil prices. The Company's gas production decreased by 49 thousand MCF, and
the average price received per MCF increased from $3.08 to $3.32.

           Production costs increased $174 thousand, or 8%, and decreased $393
thousand, or 15%, during 2001 and 2000, respectively. The primary reason for the
increase in 2001 was an increase in the number of producing wells. Depreciation,
depletion and amortization decreased $61 thousand, or 1%, between 2000 and 2001.
The primary reason for this decrease is lower production volumes, although the
impact of the decrease in production volumes was offset by




                                      -22-
<PAGE>

lower reserves. Depreciation, depletion and amortization decreased $252
thousand, or 5%, between 1999 and 2000.

           Well management and operating revenues increased $25 thousand, or 6%,
from 2000 to 2001. Well management and operating costs increased $45 thousand,
or 37%, from 2000 to 2001. The reason for these increases in well management and
operating revenues and costs was due to the increase in Company operated oil and
gas interests. Well management and operating revenues increased $7 thousand, or
2%, from 1999 to 2000. Well management and operating costs increased $16
thousand, or 15%, from 1999 to 2000.

           Abandonments and write downs of oil and gas properties decreased $200
thousand between 2000 and 2001 and decreased $249 thousand between 1999 and
2000. These decreases were attributable to a reduction in the write down of oil
and gas properties and abandonments of oil and gas properties. During 2001 and
2000, the Company had no impairment on its oil and gas properties. During 1999,
the Company wrote down oil and gas properties by approximately $601 thousand to
provide for impairment on certain of its oil and gas properties.

           General and administrative expenses increased $37 thousand, or 3%,
between 2000 and 2001, and decreased $294 thousand, or 18%, between 1999 and
2000. The primary reason for the increase during 2001 was an increase in
overhead costs associated with ongoing operations of the Company. In addition,
the decrease in general and administrative expenses between 1999 and 2000 was
the result of a reduction in personnel and related costs due to a decrease in
the level of activity in acquiring leasehold prospects and drilling activity.

                        Net other income amounted to $178 thousand, $271
thousand, and $77 thousand in 2001, 2000 and 1999, respectively. In 2001,
interest income decreased as a result of lower interest rates.

           The Company is not a tax paying entity, and the net taxable income or
loss, other than the taxable income or loss attributable to EEI, is allocated
directly to its respective partners.

           Net income decreased $749 thousand, or 9%, between 2000 and 2001. The
decrease was primarily the result of a decrease in oil and gas sales. Net income
increased $3.1 million, or 58%, between 1999 and 2000. The increase resulted
from increased oil and gas sales and the decreases in direct costs and general
and administrative expenses. Net income represented 48%, 51% and 36% of total
revenues during the years ended December 31, 2001, 2000 and 1999, respectively.




                                      -23-
<PAGE>



NEW ACCOUNTING STANDARDS

           In June 1998, SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities," was issued. SFAS No. 133 establishes accounting and
reporting standards for derivative instruments and hedging activities. SFAS No.
133, as amended by SFAS No. 137, is effective for all fiscal quarters of all
fiscal years beginning after June 15, 2000. In June 2001, the Financial
Accounting Standards Board ("FASB") issued SFAS No. 141, "Business
Combinations." SFAS No. 141 requires the purchase method of accounting for
business combinations initiated after June 30, 2001 and eliminates the
pooling-of-interest method and further clarifies the criteria to recognize
intangible assets separately from goodwill. The adoption of SFAS Nos. 133 and
141 had no material effect on the Company's financial statements.

           In June 2001, FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets." Under SFAS No. 142, goodwill and intangible assets deemed to
have indefinite lives will no longer be amortized but will be subject to
periodic impairment tests. Other intangible assets will continue to be amortized
over their useful lives. SFAS No. 142 is effective for fiscal years beginning
after December 15, 2001. In June 2001, FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations," which is effective the first quarter of fiscal
year 2003. SFAS 143 addresses financial accounting and reporting for obligations
associated with the retirement of long-lived assets and the associated asset
retirement cost. In August 2001, FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-lived Assets," which is effective the first
quarter of fiscal year 2002. SFAS No. 144 modifies and expands the financial
accounting and reporting for the impairment or disposal of long-lived assets
other than goodwill. The Company is still evaluating the impact of these new
standards, but at this time does not believe their adoption will have a
significant impact on its financial position and results of operations.

INFLATION AND CHANGES IN PRICES

           While the cost of operations is affected by inflation, oil and gas
prices have fluctuated in recent years and generally have not matched inflation.
The price of oil in the Appalachian Basin has ranged from a low of $8.50 per
barrel in December 1998 to a high of $33.25 in September 2000. As of March 20,
2002, the posted field price in the Appalachian Basin area, the Company's
principal area of operation, was $21.25 per barrel of oil. Although the
Company's sales are affected by this type of price instability, the impact on
the Company is not as dramatic as might be expected since less than 9% of the
Company's total future cash inflows related to oil and gas reserves as of
December 31, 2001 are comprised of oil reserves.

           Natural gas prices have also fluctuated more recently. Under the
various gas purchase agreements with Dominion Field Services, Inc. and its
affiliates (including The East Ohio Gas Company), adjustments to the price of
gas paid to the Company were based on 80% of the increase or decrease in
Dominion's average GCR rates. The Company's average price of gas during 1999
amounted to $3.08 per MCF. The Company's average price of gas during 2000
increased $.24 to $3.32 compared to 1999. The Company's average price of gas
during 2001







                                      -24-
<PAGE>

increased $.61 to $3.93 compared to 2000. The price of gas in the Appalachian
Basin increased significantly throughout 2000 and reached a high of more than
$10.00 per MCF in January 2001. The Company's gas is currently sold under
short-term contracts where the price is determined using a monthly strip price.
The Company at times will lock-in a monthly strip price over certain time
periods. Excess gas production above locked-in quantities is sold at a price
tied to the then current monthly NYMEX settled price. As of March 20, 2001, the
current one-year strip price for Henry Hub Natural Gas on the NYMEX is $3.42 per
MCF. The Company's sales are significantly impacted by pricing instability in
the natural gas market. One of the consequences of these pricing fluctuations is
evident in the Company's Standardized Measure of Discounted Future Net Cash
Flows increasing from $53.7 million at December 31, 1999 to $82.0 million at
December 31, 2000, and then decreasing to $45.1 million at December 31, 2001.

           The Company's Standardized Measure of Discounted Future Net Cash
Flows decreased by $36.9 million from December 31, 2000 to December 31, 2001 and
increased by $28.3 million from December 31, 1999 to December 31, 2000. A
reconciliation of the Changes in the Standardized Measures of Discounted Future
Net Cash Flows is included in the Company's consolidated financial statements.

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
------------------------------------------------------------------------

           The Company is exposed to market risk from changes in interest rates
since it, at times, funds its operations through long-term and short-term
borrowings. The Company's primary interest rate risk exposure results from
floating rate debt with respect to the Company's revolving credit. At December
31, 2001, none of the Company's total long-term debt consisted of floating rate
debt.

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
-----------------------------------------------------

           See attached pages F-1 to F-23.

ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
-----------------------------------------------------------
           ACCOUNTING AND FINANCIAL DISCLOSURE
           -----------------------------------

           Not applicable.









                                      -25-
<PAGE>




                                    PART III
                                    --------


ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
-------------------------------------------------------------

           The Company, as a limited partnership, does not have any directors or
executive officers. The General Partner of the Company is Everflow Management
Limited, LLC, an Ohio limited liability company formed in March 1999, as the
successor to the Company's original general partner. The members of the General
Partner as of March 20, 2002 are Everflow Management Corporation, an Ohio
corporation ("EMC"), Thomas L. Korner and William A. Siskovic, all of whom are
directors and/or officers of EEI, and Sykes Associates, a limited partnership
controlled by Robert F. Sykes, Chairman of the Board of EEI.

           EMC is the Managing Member of the General Partner. EMC was formed in
September 1990 to act as the Managing General Partner of Everflow Management
Company, the predecessor of the General Partner. EMC is owned by the other
members of the General Partner and EMC currently has no employees, but as
Managing Member of the General Partner, makes all management and business
decisions on behalf of the General Partner and thus on behalf of the Company.

           EEI has continued its separate existence and provides general,
administrative, management and leasehold functions for the Company. Personnel
previously employed by EEI to conduct its operation, drilling and field
supervisory functions have become employed directly by the Company and discharge
the same functions on behalf of the Company. All of EEI's outstanding shares are
owned by the Company.

           DIRECTORS AND OFFICERS OF EEI AND EMC. The executive officers and
directors of EEI and EMC as of March 20, 2002 are as follows:

<TABLE>
<CAPTION>
                                                      Positions and                   Positions and
         Name                     Age                Offices With EEI                Offices With EMC
---------------------             ---          -------------------------        --------------------------

<S>                               <C>          <C>                              <C>
Robert F. Sykes                   78           Chairman of the Board             Chairman of the Board
                                                                                 and Director

Thomas L. Korner                  48           President and Director            President and Director

David A. Kidder                   63           Treasurer                         None

William A. Siskovic               46           Vice President, Secretary,        Vice President, Secretary-
Principal Financial and                        Treasurer, Principal
                                               Accounting Officer and            Financial and Accounting
                                               Director                          Officer and Director
</TABLE>







                                      -26-
<PAGE>
..
All directors of EEI are elected to serve by the Company, which is EEI's sole
shareholder. All officers of EEI serve at the pleasure of the Board of
Directors. Directors and officers of EEI receive no compensation or fees for
their services to EEI or their services on behalf of the Company.

           All directors and officers of EMC hold their positions with EMC
pursuant to a shareholders' agreement among EMC and such directors and officers.
The shareholders agreement controls the operation of EMC, provides for changes
in share ownership of EMC, and determines the identity of the directors and
officers of EMC as well as their replacement.

ROBERT F. SYKES has been a Director of EEI since March 1987 and Chairman of the
Board since May 1988. Mr. Sykes is the Chairman of the Board and a Director of
EMC and has served in such capacities since its formation in September 1990. He
was the Chairman of the Board of Sykes Datatronics, Inc., Rochester, New York,
from its organization in 1986 until his resignation in January 1989. Sykes
Datatronics, Inc. is a manufacturer of telephone switching equipment. Mr. Sykes
also served as President and Chief Executive Officer of Sykes Datatronics, Inc.
from 1968 until October 1983 and from January 1985 until October 1985. Mr. Sykes
also has been a Director of Voplex, Inc., Rochester, New York, a manufacturer of
plastic products, and a Director of ACC Corp., a long distance telephone
company.

THOMAS L. KORNER has been President of EEI and EMC since November 1995 and the
President and Treasurer of Everflow Nominee. Mr. Korner is also a Director of
EMC and has served in such capacity since its formation in September 1990. He
served as Vice President and Secretary of EEI from April 1985 to November 1995
and as Vice President and Secretary of EMC from September 1990 to November 1995.
He served as the Treasurer of EEI from June 1982 to June 1986. Mr. Korner
supervises and oversees all aspects of EEI's business, including oil and gas
property acquisition, development, operation and marketing. Prior to joining EEI
in June 1982, Mr. Korner was a practicing certified public accountant with Hill,
Barth and King, certified public accountants, and prior to that with Arthur
Andersen & Co., certified public accountants. He has a Business Administration
Degree from Mt. Union College.

DAVID A. KIDDER has been the Treasurer of EEI since June 1986 and has been
employed by EEI since April 1985. From 1983 to 1985, he was Treasurer of LGM
Corporation, Columbus, Ohio, an oil and gas service company; from 1982 to 1983,
he was Treasurer of OPEX, Inc., Columbus, Ohio, a producer of oil and gas; and
from 1980 to 1981, he was Treasurer of United Petroleum, Inc., Columbus, Ohio, a
producer of oil and gas. From 1973 to 1980, Mr. Kidder was involved in the oil
and gas industry in various financial and accounting capacities. Prior to that
time, Mr. Kidder practiced as a certified public accountant with Coopers &
Lybrand, certified public accountants. Mr. Kidder has a Bachelor of Arts Degree
in Accounting from the University of Cincinnati.

WILLIAM A. SISKOVIC has been a Vice President of EEI since January 1989. Mr.
Siskovic is a Vice President, Secretary-Treasurer, Principal Financial and
Accounting Officer and a Director of EMC. He has served as Principal Financial
Officer and Secretary of EMC since November 1995 and in all other capacities
since the formation of EMC in September 1990. He is



                                      -27-
<PAGE>

responsible for the financial operations of the Company and EEI. From August
1980 to July 1984, Mr. Siskovic served in various financial and accounting
capacities including Assistant Controller of Towner Petroleum Company, a public
independent oil and gas operator, producer and drilling fund sponsor company.
From August 1984 to September 1985, Mr. Siskovic was a Senior Consultant for
Arthur Young & Company, certified public accountants, where he was primarily
responsible for the firm's oil and gas consulting practice in the Cleveland,
Ohio office. From October 1985 until joining EEI in April 1988, Mr. Siskovic
served as Controller and Principal Accounting Officer of Lomak Petroleum, Inc.,
a public independent oil and gas operator and producer. He has a Business
Administration Degree in Accounting from Cleveland State University.

           COMPLIANCE TO SECTION 16(a) OF THE EXCHANGE ACT. Section 16(a) of the
Securities Exchange Act of 1934 requires the Company's officers and directors,
and persons who own more than 10% of the Units to file reports of ownership and
changes in ownership with the Securities and Exchange Commission. Officers,
directors and greater than 10% Unitholders are required by SEC regulation to
furnish the Company with copies of all Section 16(a) forms they file.

           Based solely on the Company's review of the copies of such forms
furnished to the Company, the Company believes that its officers, directors and
greater than 10% beneficial owners complied with all Section 16(a) filing
requirements for 2001.

ITEM 11.   EXECUTIVE COMPENSATION
---------------------------------

           As a limited partnership the Company has no executive officers or
directors, but is managed by the General Partner. The executive officers of EMC
and EEI are compensated either directly by the Company or indirectly through
EEI. The compensation described below represents all compensation from either
the Company or EEI.

           The following table sets forth information concerning the annual and
long-term compensation for services in all capacities to the Company for the
fiscal years ended December 31, 2001, 2000 and 1999, of those persons who were,
at December 31, 2001: (i) the chief executive officer; and (ii) the other highly
compensated executive officer of the Company. The Chief Executive Officer and
such other executive officer are hereinafter referred to collectively as the
"Named Executive Officers."





                                      -28-
<PAGE>


<TABLE>
<CAPTION>

                                                     SUMMARY COMPENSATION TABLE

                                                        Annual Compensation
                                            ----------------------------------------------------
                                                                                           Other
                                                                                          Annual             All Other
              Name and                                                                    Compen-             Compen-
         Principal Position                 Year        Salary           Bonus            sation              sation  (1)
         ------------------                 ----        ------           -----          ---------          ------------

<S>                                         <C>      <C>              <C>              <C>                 <C>
Thomas L. Korner                            2001     $  83,000        $  72,500        $   1,821           $  54,051(2)
President                                   2000        80,000           40,000            2,008              47,425(2)
                                            1999        80,000           60,000            1,954              36,710(2)

William A. Siskovic                         2001        83,000           72,500            1,544              44,955(3)
Vice President and                          2000        80,000           40,000            1,749              40,201(3)
Principal Financial and                     1999        80,000           60,000            1,326              28,420(3)
Accounting Officer
</TABLE>
-----------------------------------
No Named Executive Officer received personal benefits or perquisites during
2001, 2000 and 1999 in excess of the lesser of $50,000 or 10% of his aggregate
salary and bonus.

(1)         Includes amounts received from participation in certain overriding
            royalty interest arrangements organized by EEI. Also includes
            amounts contributed under the Company's 401(K) Retirement Savings
            Plan. The Company matched employees' contributions to the 401(K)
            Retirement Savings Plan to the extent of 50% of the first 6% of a
            participant's salary reduction in 1999. Beginning in 2000, the
            Company matched employees' contributions to the 401(K) Retirement
            Savings Plan to the extent of 100% of the first 6% of a
            participant's salary reduction. The amounts attributable to the
            Company's matching contribution vest immediately.
(2)         Includes amounts received by Thomas L. Korner from participation in
            certain overriding royalty interest arrangements organized by EEI of
            $44,721, $40,225 and $28,310 in 2001, 2000 and 1999, respectively.
 (3)        Includes amounts received by William A. Siskovic from participation
            in certain overriding royalty interest arrangements organized by EEI
            of $35,625, $33,001 and $20,020 in 2001, 2000 and 1999,
            respectively.

The General Partner, EMC and the members do not receive any separate
compensation or reimbursement for their management efforts on behalf of the
Company. All direct and indirect costs incurred by the Company are borne by the
General Partner of the Company and the Unitholders as Limited Partners of the
Company in proportion to their respective interest in the Company. The members
are not entitled to any fees or other compensation as a result of the
acquisition or operation of oil and gas properties by the Company. The members,
in their individual capacities, are not entitled to share in distributions from
or income of the Company on an ongoing basis, upon liquidation or otherwise. The
members only share in the revenues, income and distributions of the Company
indirectly through their ownership of the General Partner of the Company. The
General Partner is entitled to share in the income and expense of the Company on
the basis of its interests in the Company. The General Partner through it
predecessor, Everflow Management Company, contributed Interests (as defined and
described in "Item 1. Business" above) with an Exchange value of $670,980 for
its interest as a general partner in the Company.

           None of the officers of the Company has an employment agreement.





                                      -29-
<PAGE>

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
-------------------------------------------------------------------------

           The General Partner is a limited liability company of which EMC, an
Ohio corporation is the Managing Member. The members of the General Partner are
Thomas L. Korner and William A. Siskovic, both of whom are directors and
officers of EEI, and Sykes Associates, a limited partnership controlled by
Robert F. Sykes, Chairman of the Board of EEI and EMC. The General Partner of
the Company, owns a 1.1493% interest in the Company. The members and their
affiliates currently hold (in addition to the General Partner's interest in the
Company) 1,261,440 Units, representing approximately 21.86% of the outstanding
Units.

           The following table sets forth certain information with respect to
the number of Units beneficially owned as of March 20, 2002 by each person known
to the management of the Company to own beneficially more than 5% of the
outstanding Units; by each director and officer of EMC; and by all directors and
officers as a group. The table also sets forth (i) the ownership interests of
the General Partner, and (ii) the ownership of EMC.
<TABLE>
<CAPTION>

                                                       BENEFICIAL OWNERSHIP OF UNITS IN THE COMPANY,
                                                          EVERFLOW MANAGEMENT LIMITED, LLC AND EMC

                                                                                                Percentage
                                                                                               Interest in
                                                                       Percentage                Everflow           Percentage
                   Name                            Units                of Units                Management          Interest in
                 Of Holder                      in Company            in Company(1)           Limited, LLC(2)           EMC
--------------------------------------          ----------            -------------           ---------------        ---------
<S>                                               <C>                    <C>                      <C>                 <C>
Robert F. Sykes(3)                                1,056,464              18.31                    66.6666             66.6666
Thomas L. Korner                                    135,910               2.35                    16.6667             16.6667
William A. Siskovic                                  69,066               1.20                    16.6667             16.6667
All officers and directors as
   a group (3 persons in EMC)                     1,261,440              21.86                   100.0000            100.0000
</TABLE>

(1)   Does not include the interest in the Company owned indirectly by such
      individuals as a result of their ownership in (i) the General Partner
      (based on its 1.15% interest in the Company) or (ii) EMC (based on EMC's
      1% managing member's interest in the General Partner).

(2)   Includes the interest in the General Partner owned indirectly by such
      individuals as a result of their share ownership in EMC resulting from
      EMC's 1% managing member's interest in the General Partner.

(3)   Includes 732,855 Units held by Sykes Associates, a New York limited
      partnership comprised of Mr. Sykes and his wife as general partners and
      four adult children as limited partners, 162,462 Units of the Company held
      by the Robert F. Sykes Annuity Trust and 161,147 Units held by the
      Catherine Sykes Annuity Trust.


ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
----------------------------------------------------------

            In the past, certain officers, directors and more than 10%
Unitholders of the Company have invested, and may in the future invest, in oil
and gas programs sponsored by EEI on the same terms as unrelated investors. In
the past, certain officers, directors and/or more than 10% Unitholders of the
Company have frequently participated and will likely participate in the future
as working interest owners in wells in which the Company has an interest. The
Company



                                      -30-
<PAGE>

anticipates that any such participation by individual members of the Company's
management would enable such individuals to participate in the drilling and
development of undeveloped drillsites on an equal basis with the Company or the
particular drilling program acquiring such drillsites, which participation would
be on a uniform basis with respect to all drilling conducted during a specified
time frame, as opposed to selective participation. Frequently, such
participation has been on more favorable terms than the terms which were
available to unrelated investors. Frequently, EEI loaned the officers of the
Company the funds necessary to participate in the drilling and development of
such wells. Such loans currently accrue interest at the rate of LIBOR plus 150
basis points per annum. As of December 31, 2001, the aggregate outstanding
balance of such indebtedness was approximately $4,000 and $73,000 owing from
Thomas L. Korner and William A. Siskovic, respectively.

            Certain officers and directors of EMC own oil and gas properties
and, as such, contract with the Company to provide field operations on such
properties. These ownership interests are charged per well fees for such
services on the same basis as all other working interest owners.


















                                      -31-
<PAGE>



                                     PART IV
                                     -------


ITEM 14.      EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
-----------------------------------------------------------------------------

(a)    (1)    Financial Statements
              --------------------

              The following Consolidated Financial Statements of the Registrant
and its subsidiaries are included in Part II, Item 8:

                                                                       Page(s)
                                                                       -------

Auditors' Report on Audited Financial Statements                         F-3
         Balance Sheets                                               F-4 - F-5
         Statements of Income                                            F-6
         Statements of Partners' Equity                                  F-7
         Statements of Cash Flows                                        F-8
         Notes to Financial Statements                               F-9 - F-23

(a)    (2)    Financial Statements Schedules
              -------------------------------

              All schedules for which provision is made in the applicable
accounting regulation of the Securities and Exchange Commission are not required
under the related instructions or are inapplicable, and therefore have been
omitted.

(a)    (3)    Exhibits
              --------

              See the Exhibit Index at page E-1 of this Annual Report on Form
10-K.

























                                      -32-
<PAGE>


                                  Exhibit Index
                                  -------------



       Exhibit No.                  Description
       -----------                  -----------

           4.1        Certificate of Limited Partnership of the            (1)
                      Registrant dated September 13, 1990, as
                      filed with the Delaware Secretary of State
                      on September 14, 1990

           4.2        Form of Agreement of Limited Partnership of          (1)
                      the Registrant

           4.3        General Partnership Agreement of Everflow            (1)
                      Management Company

           4.4        Articles of Incorporation of Everflow                (1)
                      Management Corporation

           4.5        Code of Regulations of Everflow Management           (1)
                      Corporation

           4.6        Shareholders Agreement for Everflow                  (1)
                      Management Corporation

           4.7        Third Amended and Restated Loan Agreement,           (2)
                      dated as of May 1, 1991 between Everflow
                      Eastern, Inc., the Registrant and the banks
                      listed therein, with National Bank of
                      Detroit as Agent

           4.8        First Amendment to Third Amended and                 (5)
                      Restated Loan and Security Agreements dated
                      July 1, 1993, between Everflow Eastern,
                      Inc. and Everflow Eastern Partners, L.P.
                      and the banks listed therein, with National
                      Bank of Detroit as Agent

           4.9        Revolving Credit Note to First Amendment to          (5)
                      Third Amended and Restated Loan and
                      Security Agreement dated as of July 1, 1993

           4.10       Credit Agreement dated January 19, 1995              (8)
                      between Everflow Eastern, Inc. and Everflow
                      Eastern Partners, L.P. and Bank One, Texas,
                      National Association


                               E-1

<PAGE>
                                  Exhibit Index
                                  -------------



       Exhibit No.                       Description
       -----------                       -----------

           4.11       Amendment to Credit Agreement dated                  (13)
                      February 23, 1996 between Everflow Eastern,
                      Inc. and Everflow Eastern Partners, L.P.
                      and Bank One, Texas, National Association

           4.12       Second Amendment to Credit Agreement dated           (13)
                      December 30, 1996 between Everflow Eastern,
                      Inc. and Everflow Partners, L.P. and Bank
                      One, Texas, National Association

           4.13       Loan Modification Agreement dated June 16,           (14)
                      1997 between Bank One, N.A., Bank One,
                      Texas, N.A. and Everflow Eastern, Inc. and
                      Everflow Eastern Partners, L.P.

           4.14       Loan Modification Agreement dated May 29,            (15)
                      1998 between Bank One, N.A., Successor to
                      Bank One, Texas, N.A., and Everflow
                      Eastern, Inc. and Everflow Eastern Partners
                      L.P.

           4.15       Articles of Organization of Everflow                 (17)
                      Management Limited, LLC

           4.16       Operating Agreement of Everflow Management           (17)
                      Limited, LLC dated March 8, 1999

           4.17       Loan Modification Agreement dated May 25,            (18)
                      1999 between Bank One, N.A., and Everflow
                      Eastern, Inc. and Everflow Eastern
                      Partners, L.P.

           4.18       Loan Modification Agreement dated September          (19)
                      19, 2000, between Bank One, N.A., and
                      Everflow Eastern, Inc. and Everflow Eastern
                      Partners, L.P.

           4.19       Loan Modification Agreement dated August             (20)
                      28, 2001 between Bank One, N.A., and
                      Everflow Eastern, Inc. and Everflow Eastern
                      Partners, L.P.

           10.1       Lease Agreement dated June 30, 1984 by and           (1)
                      between Village Green Associates, Inc. and
                      Everflow Eastern, Inc.

           10.2       Gas Purchase Agreement dated September 3,            (3)
                      1991 by and between the Registrant and The
                      East Ohio Gas Company



                               E-2

<PAGE>

     Exhibit No.      Description
     -----------      -----------

           10.3       Intermediate Term Adjustable Price Gas               (4)
                      Purchase Agreement, contract #10342, dated
                      October 9, 1992, between The East Ohio Gas
                      Company and Everflow Eastern Partners, L.P.

           10.4       Quaker State Full Load Crude Oil Purchase            (4)
                      Agreement dated January 13, 1993, between
                      Quaker State Oil Refining Corporation and
                      Everflow Eastern Partners, L.P.

           10.5       Intermediate Term Adjustable Gas Purchase            (6)
                      Agreement, Contract #10461, dated March 10,
                      1994, between The East Ohio Gas Company and
                      Everflow Eastern Partners, L.P.

           10.6       Intermediate Term Adjustable Gas Purchase            (7)
                      Agreement, Contract #10515, dated August
                      10, 1994, between The East Ohio Gas Company
                      and Everflow Eastern Partners, L.P.

           10.7       Operating facility lease dated October 3,            (9)
                      1995 between Everflow Eastern Partners,
                      L.P. and A-1 Storage of Canfield, Ltd.

           10.8       Intermediate Term Adjustable Gas Purchase            (11)
                      Agreement, Contract #11245, dated May 29,
                      1996, between The East Ohio Gas Company and
                      Everflow Eastern Partners, L.P.

           10.9       Intermediate Term Adjustable Gas Purchase            (11)
                      Agreement, Contract #11285, dated May 29,
                      1996, between The East Ohio Gas Company and
                      Everflow Eastern Partners, L.P.

           10.10      One Year Term Gas Purchase Agreement dated           (12)
                      August 1, 1996, between Everflow Eastern
                      Partners, L.P. and JDS Energy Corporation

           10.11      One Year Term Gas Purchase Agreement dated           (13)
                      January 20, 1997, between Everflow Eastern
                      Partners, L.P. and JDS Energy Corporation

           10.12      Gas Purchase Agreement, Contract #11467,             (16)
                      dated November 1, 1997, between Everflow
                      Eastern Partners, L.P. and CNG Energy
                      Services Corporation.



                               E-3
<PAGE>

       Exhibit No.                    Description
       -----------                    -----------

           10.13      One Year Term Gas Purchase Agreement dated           (16)
                      November 1, 1998, between Everflow Eastern
                      Partners, L.P. and JDS Energy Systems, Inc.

           22.1       Subsidiaries of the Registrant                       (10)

--------------------

(1)         Incorporated herein by reference to the appropriate exhibit to
            Registrant's Registration Statement on Form S-1 (Reg. No. 33-36919).

(2)         Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the second quarter
            ended June 30, 1991.

(3)         Incorporated herein by reference to the appropriate exhibit to
            Registrant's Annual Report on Form 10-K for the year ended December
            31, 1991 (File No. 0-19279).

(4)         Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Annual Report on Form 10-K for the year ended December
            31, 1992 (File No. 0-19279).

(5)         Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the second quarter
            ended June 30, 1993.

(6)         Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the second quarter
            ended June 30, 1994.

(7)         Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the third quarter
            ended September 30, 1994.

(8)         Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Annual Report on Form 10-K for the year ended December
            31, 1994 (File No. 0-19279).

(9)         Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the third quarter
            ended September 30, 1995.

(10)        Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Annual Report on Form 10-K for the year ended December
            31, 1995 (File No. 0-19279).

(11)        Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the second quarter
            ended June 30, 1996.

(12)        Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the third quarter
            ended September 30, 1996.

(13)        Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Annual Report on Form 10-K for the year ended December
            31, 1996 (File No. 0-19279).

(14)        Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the second quarter
            ended June 30, 1997.

(15)        Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the second quarter
            ended June 30, 1998.

(16)        Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Annual Report on Form 10-K for the year ended December
            31, 1998 (File No. 0-19279).

(17)        Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the first quarter
            ended March 31, 1999.

(18)        Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the second quarter
            ended June 30, 1999.

(19)        Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the third quarter
            ended September 30, 2000.

(20)        Incorporated herein by reference to the appropriate exhibit to the
            Registrant's Quarterly Report on Form 10-Q for the third quarter
            ended September 30, 2001.




                                      E-4
<PAGE>



                                   SIGNATURES
                                   ----------

            Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.

EVERFLOW EASTERN PARTNERS, L.P.

By:    EVERFLOW MANAGEMENT LIMITED, LLC
       General Partner
By:    EVERFLOW MANAGEMENT CORPORATION
       Managing Member



<TABLE>
<S>                                     <C>                            <C>
By:    /s/Robert F. Sykes               Director                       March  27 , 2001
       ------------------------------                                        ----
       Robert F. Sykes



By:    /s/Thomas L. Korner              President and Director         March  27 , 2001
       ------------------------------                                        ----
       Thomas L. Korner



By:    /s/William A. Siskovic           Vice President,                March  27 , 2001
       ------------------------------   Secretary-Treasurer                  ----
       William A. Siskovic              and Director (principal
                                        financial and accounting
                                        officer)



</TABLE>
<PAGE>














                        EVERFLOW EASTERN PARTNERS, L. P.

                       2001 CONSOLIDATED FINANCIAL REPORT
















                                       F-1

<PAGE>





                        EVERFLOW EASTERN PARTNERS, L. P.

                                    CONTENTS



------------------------------------------------------------------------------

                                                            Page
                                                            ----

AUDITORS' REPORT ON THE FINANCIAL STATEMENTS                 F-3

FINANCIAL STATEMENTS
    Consolidated balance sheets                           F-4 - F-5
    Consolidated statements of income                        F-6
    Consolidated statements of partners' equity              F-7
    Consolidated statements of cash flows                    F-8
    Notes to consolidated financial statements           F-9 - F-24












                                       F-2

<PAGE>










                          Independent Auditors' Report
                          ----------------------------


To the Partners
Everflow Eastern Partners, L. P.
Canfield, Ohio


          We have audited the accompanying consolidated balance sheets of
Everflow Eastern Partners, L. P. and subsidiaries as of December 31, 2001 and
2000, and the related consolidated statements of income, partners' equity, and
cash flows for each of the three years in the period ended December 31, 2001.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.

          We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

          In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
Everflow Eastern Partners, L. P. and subsidiaries as of December 31, 2001 and
2000, and the consolidated results of their operations and their cash flows for
each of the three years in the period ended December 31, 2001, in conformity
with accounting principles generally accepted in the United States of America.



                                                  HAUSSER + TAYLOR LLP



Cleveland, Ohio
March 14, 2002, except for Note 8,
    dated March 20, 2002








                                       F-3

<PAGE>




                        EVERFLOW EASTERN PARTNERS, L. P.

                           CONSOLIDATED BALANCE SHEETS

                           December 31, 2001 and 2000
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>



                                                                                2001                  2000
                                                                                ----                  ----
                ASSETS
                ------

<S>                                                                        <C>                     <C>
CURRENT ASSETS
  Cash and equivalents                                                     $  1,128,835            $  1,997,978
    Accounts receivable:
     Production                                                               2,475,123               3,078,235
     Officers and employees                                                     255,448                 406,842
     Joint venture partners                                                     121,458                 114,708
    Short-term investments                                                    3,790,562               3,623,374
    Other                                                                        47,998                  79,729
                                                                           ------------            ------------
           Total current assets                                               7,819,424               9,300,866

PROPERTY AND EQUIPMENT
  Proved properties (successful efforts accounting method)                  114,964,451             112,341,851
  Pipeline and support equipment                                                504,222                 504,222
  Corporate and other                                                         1,465,910               1,539,824
                                                                           ------------            ------------
                                                                            116,934,583             114,385,897
  Less accumulated depreciation, depletion, amortization
    and write down                                                           72,609,314              68,746,486
                                                                           ------------            ------------
                                                                             44,325,269              45,639,411

  OTHER ASSETS                                                                  109,572                 103,017
                                                                           ------------            ------------

                                                                           $ 52,254,265            $ 55,043,294
                                                                           ============            ============

</TABLE>










The accompanying notes are an integral part of these financial statements.

                                      F-4

<PAGE>




                        EVERFLOW EASTERN PARTNERS, L. P.

                           CONSOLIDATED BALANCE SHEETS

                           December 31, 2001 and 2000
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>



                                                                              2001                     2000
                                                                          -----------               -----------
       LIABILITIES AND PARTNERS' EQUITY
       --------------------------------

<S>                                                                       <C>                       <C>
CURRENT LIABILITIES
  Current portion of long-term debt                                       $    53,900               $    58,595
  Accounts payable                                                            505,246                 1,018,959
  Accrued expenses                                                            275,010                   292,684
                                                                          -----------               -----------
        Total current liabilities                                             834,156                 1,370,238

LONG-TERM DEBT, NET OF CURRENT PORTION                                        458,114                   579,227

DEFERRED INCOME TAXES                                                          50,000                    50,000

COMMITMENTS AND CONTINGENCIES

LIMITED PARTNERS' EQUITY, SUBJECT TO REPURCHASE
  RIGHT
    Authorized - 8,000,000 units
    Issued and outstanding - 5,771,174 and
      5,888,662 units, respectively                                        50,326,874                52,446,234

GENERAL PARTNER'S EQUITY                                                      585,121                   597,595
                                                                          -----------               -----------
        Total partners' equity                                             50,911,995                53,043,829
                                                                          -----------               -----------

                                                                          $52,254,265               $55,043,294
                                                                          ===========               ===========

</TABLE>








The accompanying notes are an integral part of these financial statements.

                                      F-5

<PAGE>




                        EVERFLOW EASTERN PARTNERS, L. P.

                        CONSOLIDATED STATEMENTS OF INCOME

                  Years Ended December 31, 2001, 2000 and 1999
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>


                                                                     2001                2000                 1999
                                                                     ----                ----                 ----
<S>                                                            <C>                   <C>                   <C>
REVENUES
  Oil and gas sales                                            $ 15,805,040          $ 16,490,904          $ 14,639,109
  Well management and operating                                     453,774               428,497               421,799
  Other                                                               2,406                 1,738                 2,262
                                                               ------------          ------------          ------------
                                                                 16,261,220            16,921,139            15,063,170

DIRECT COST OF REVENUES
  Production costs                                                2,419,260             2,244,926             2,638,217
  Well management and operating                                     168,937               123,265               106,965
  Depreciation, depletion and amortization                        4,449,545             4,510,787             4,762,466
  Abandonment and write down of oil and gas
    properties                                                      200,000               400,000               648,742
                                                               ------------          ------------          ------------
       Total direct cost of revenues                              7,237,742             7,278,978             8,156,390

GENERAL AND ADMINISTRATIVE EXPENSE                                1,359,378             1,322,260             1,615,932
                                                               ------------          ------------          ------------
       Total cost of revenues                                     8,597,120             8,601,238             9,772,322
                                                               ------------          ------------          ------------

INCOME FROM OPERATIONS                                            7,664,100             8,319,901             5,290,848

OTHER INCOME (EXPENSE)
  Interest income                                                   222,764               316,091               157,348
  Interest expense                                                  (44,702)              (46,239)             (101,759)
  Gain on sale of property and equipment and other
    assets                                                             --                   1,004                21,504
                                                               ------------          ------------          ------------
                                                                    178,062               270,856                77,093
                                                               ------------          ------------          ------------

INCOME BEFORE CREDIT FOR INCOME TAXES                             7,842,162             8,590,757             5,367,941

CREDIT FOR INCOME TAXES
  Deferred                                                             --                    --                 (78,000)
                                                               ------------          ------------          ------------

NET INCOME                                                     $  7,842,162          $  8,590,757          $  5,445,941
                                                               ============          ============          ============


Allocation of Partnership Net Income
  Limited Partners                                             $  7,752,932          $  8,495,622          $  5,387,013
  General Partner                                                    89,230                95,135                58,928
                                                               ------------          ------------          ------------

                                                               $  7,842,162          $  8,590,757          $  5,445,941
                                                               ============          ============          ============


Net income per unit                                            $       1.33          $       1.42          $       0.88
                                                               ============          ============          ============

</TABLE>





The accompanying notes are an integral part of these financial statements.

                                      F-6

<PAGE>




                                    EVERFLOW EASTERN PARTNERS, L. P.

                              CONSOLIDATED STATEMENTS OF PARTNERS' EQUITY

                              Years Ended December 31, 2001, 2000 and 1999
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>



                                                                        2001                  2000                 1999
                                                                        ----                  ----                 ----

<S>                                                                <C>                  <C>                  <C>
PARTNERS' EQUITY - JANUARY 1                                       $ 53,043,829         $ 53,288,759         $ 52,171,076


  Net income                                                          7,842,162            8,590,757            5,445,941


  Cash distributions ($1.50 per unit in 2001, $1.25 per
    unit in 2000 and $.625 per unit in 1999)                         (8,830,838)          (7,573,783)          (3,880,436)


  Purchase and retirement of Units                                   (1,143,158)          (1,261,904)            (447,822)
                                                                   ------------         ------------         ------------


PARTNERS' EQUITY - DECEMBER 31                                     $ 50,911,995         $ 53,043,829         $ 53,288,759
                                                                   ============         ============         ============
</TABLE>












The accompanying notes are an integral part of these financial statements.

                                      F-7

<PAGE>





                        EVERFLOW EASTERN PARTNERS, L. P.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                  Years Ended December 31, 2001, 2000 and 1999
--------------------------------------------------------------------------------
<TABLE>
<CAPTION>

                                                                                    2001                2000                1999
                                                                                    ----                ----                ----
<S>                                                                            <C>                 <C>                 <C>
CASH FLOWS FROM OPERATING ACTIVITIES
  Net income                                                                   $  7,842,162        $  8,590,757        $  5,445,941
  Adjustments to reconcile net income to net cash
    provided by operating activities:
      Depreciation, depletion and amortization                                    4,508,950           4,569,114           4,819,592
      Abandonment and write down of oil and gas
        properties                                                                  200,000             400,000             648,742
      Gain on sale of property and equipment and other
        assets                                                                         --                (1,004)            (21,504)
      Deferred income taxes                                                            --                  --               (78,000)
      Changes in assets and liabilities:
         Accounts receivable                                                        596,362            (678,290)            450,714
         Short-term investments                                                    (167,188)         (2,110,101)            707,783
         Other current assets                                                        31,731               9,262               3,364
         Other assets                                                                (6,555)             41,629             (27,304)
         Accounts payable                                                          (513,713)           (183,646)           (464,187)
         Accrued expenses                                                           (17,674)            103,351            (201,854)
                                                                               ------------        ------------        ------------
              Total adjustments                                                   4,631,913           2,150,315           5,837,346
                                                                               ------------        ------------        ------------
                Net cash provided by operating activities                        12,474,075          10,741,072          11,283,287

CASH FLOWS FROM INVESTING ACTIVITIES
  Proceeds received on receivables from officers and
    employees                                                                       273,447             248,692             379,191
  Advances disbursed to officers and employees                                     (122,053)           (129,504)           (165,499)
  Purchase of property and equipment                                             (3,394,808)         (2,594,116)         (3,414,843)
  Purchase of other assets                                                             --               (64,050)               --
  Proceeds on sale of property and equipment and
    other assets                                                                       --                 1,433             199,818
                                                                               ------------        ------------        ------------
                Net cash used by investing activities                            (3,243,414)         (2,537,545)         (3,001,333)

CASH FLOWS FROM FINANCING ACTIVITIES
  Distributions                                                                  (8,830,838)         (7,573,783)         (3,880,436)
  Repurchase of Units                                                            (1,143,158)         (1,261,904)           (447,822)
  Proceeds from issuance of debt including revolver                                    --                  --             2,175,000
  Payments on debt including revolver                                              (125,808)            (54,467)         (3,738,609)
                                                                               ------------        ------------        ------------
                Net cash used by financing activities                           (10,099,804)         (8,890,154)         (5,891,867)
                                                                               ------------        ------------        ------------

NET INCREASE (DECREASE) IN CASH AND
  EQUIVALENTS                                                                      (869,143)           (686,627)          2,390,087

CASH AND EQUIVALENTS - JANUARY 1                                                  1,997,978           2,684,605             294,518
                                                                               ------------        ------------        ------------

CASH AND EQUIVALENTS - DECEMBER 31                                             $  1,128,835        $  1,997,978        $  2,684,605
                                                                               ============        ============        ============

Supplemental disclosures of cash flow information:
  Cash paid during the year for:
    Interest                                                                   $     42,656        $     46,239        $    112,648
    Income taxes                                                                       --                  --                  --

</TABLE>



The accompanying notes are an integral part of these financial statements.
                                      F-8

<PAGE>





                        EVERFLOW EASTERN PARTNERS, L. P.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

         A.       Organization - Everflow Eastern Partners, L. P. ("Everflow")
                  is a Delaware limited partnership which was organized in
                  September 1990 to engage in the business of oil and gas
                  exploration and development. Everflow was formed to
                  consolidate the business and oil and gas properties of
                  Everflow Eastern, Inc. ("EEI") and subsidiaries and the oil
                  and gas properties owned by certain limited partnership and
                  working interest programs managed or sponsored by EEI ("EEI
                  Programs" or "the Programs").

                  Everflow Management Limited, LLC, an Ohio limited liability
                  company, is the general partner of Everflow and, as such, is
                  authorized to perform all acts necessary or desirable to carry
                  out the purposes and conduct of the business of Everflow. The
                  members of Everflow Management Limited, LLC are Everflow
                  Management Corporation ("EMC"), two individuals who are
                  Officers and Directors of EEI and Sykes Associates, a limited
                  partnership controlled by Robert F. Sykes, the Chairman of the
                  Board of EEI. EMC is an Ohio corporation formed in September
                  1990 and is the managing member of Everflow Management
                  Limited, LLC.

         B.       Principles of Consolidation - The consolidated financial
                  statements include the accounts of Everflow, its wholly-owned
                  subsidiaries, including EEI and EEI's wholly-owned
                  subsidiaries, and investments in oil and gas drilling and
                  income partnerships (collectively, the "Company") which are
                  accounted for under the proportional consolidation method. All
                  significant accounts and transactions between the consolidated
                  entities have been eliminated.

         C.       Use of Estimates - The preparation of financial statements in
                  conformity with accounting principles generally accepted in
                  the United States of America requires management to make
                  estimates and assumptions that affect the reported amounts of
                  assets and liabilities and disclosure of contingent assets and
                  liabilities at the date of the financial statements and the
                  reported amounts of revenues and expenses during the reporting
                  period. Actual results could differ from those estimates.

         D.       Fair Value of Financial Instruments - The fair values of cash,
                  accounts receivable, short-term investments (based on quoted
                  market values), accounts payable and other short-term
                  obligations approximate their carrying values because of the
                  short maturity of these financial instruments. The carrying
                  values of the Company's long-term obligations approximate
                  their fair value. In accordance with Statement of Financial
                  Accounting Standards ("SFAS") No. 107, "Disclosure About Fair
                  Value of Financial Instruments," rates available at balance
                  sheet dates to the Company are used to estimate the fair value
                  of existing debt.

         E.       Cash Equivalents - For purposes of the statement of cash
                  flows, the Company considers all highly liquid debt
                  instruments purchased with a maturity of three months or less
                  to be cash equivalents. The Company maintains at various
                  financial institutions cash and cash equivalents which may
                  exceed federally insured amounts and which may, at times,
                  significantly exceed balance sheet amounts due to float.


                                       F-9

<PAGE>



                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
         (CONTINUED)

         F.       Property and Equipment - The Company uses the successful
                  efforts method of accounting for oil and gas exploration and
                  production activities. Under successful efforts, costs to
                  acquire mineral interests in oil and gas properties and to
                  drill and equip development wells are initially capitalized.
                  Costs of development wells (on properties the Company has no
                  further interest in) that do not find proved reserves and
                  geological and geophysical costs are expensed. The Company has
                  not participated in exploratory drilling and owns no interest
                  in unproved properties.

                  Capitalized costs of proved properties, after considering
                  estimated dismantlement and abandonment costs and estimated
                  salvage values, are amortized by the unit-of-production method
                  based upon estimated proved developed reserves. Depletion,
                  depreciation and amortization on proved properties amounted to
                  $4,417,473, $4,477,379 and $4,728,480 for the years ended
                  December 31, 2001, 2000 and 1999, respectively.

                  On sale or retirement of a unit of a proved property (which
                  generally constitutes the amortization base), the cost and
                  related accumulated depreciation, depletion, amortization and
                  write down are eliminated from the property accounts, and the
                  resultant gain or loss is recognized.

                  SFAS No. 121, "Accounting for the Impairment of Long-Lived
                  Assets and for Long-Lived Assets to be Disposed Of," requires
                  that long-lived assets (including oil and gas properties) and
                  certain identifiable intangibles be reviewed for impairment
                  whenever events or changes in circumstances indicate that the
                  carrying amount of an asset may not be recoverable. Everflow
                  utilizes a field by field basis for assessing impairment of
                  its oil and gas properties. The Company wrote down oil and gas
                  properties by approximately $200,000, $400,000 and $601,000
                  during 2001, 2000 and 1999, respectively, to provide for
                  impairment on certain of its oil and gas properties.

                  Pipeline and support equipment and other corporate property
                  and equipment are depreciated principally on the straight-line
                  method over their estimated useful lives (pipeline and support
                  equipment - 10 years, other corporate equipment - 3 to 7
                  years, other corporate property - building and improvements
                  with a cost of $1,007,107 - 40 years). Depreciation on
                  pipeline and support equipment and other corporate property
                  and equipment amounted to $91,477, $91,735 and $91,112 for the
                  years ended December 31, 2001, 2000 and 1999, respectively.

                  Maintenance and repairs of property and equipment are expensed
                  as incurred. Major renewals and improvements are capitalized,
                  and the assets replaced are retired.

         G.       Revenue Recognition - The Company recognizes revenue from oil
                  and gas production as it is extracted and sold from the
                  properties. Other revenue is recognized at the time it is
                  earned and the Company has a contractual right to such
                  revenue.


                                      F-10

<PAGE>
                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


NOTE 1.   ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
          (CONTINUED)

          G.        Revenue Recognition (Continued)

                    The Company participates (and may act as drilling
                    contractor) with unaffiliated joint venture partners in the
                    drilling, development and operation of jointly owned oil and
                    gas properties. Each owner, including the Company, has an
                    undivided interest in the jointly owned property(ies).
                    Generally, the joint venture partners participate on the
                    same drilling/development cost basis as the Company and,
                    therefore, no revenue, expense or income is recognized on
                    the drilling and development of the properties. Accounts
                    receivable from joint venture partners consist principally
                    of drilling and development costs the Company has advanced
                    or incurred on behalf of joint venture partners. The Company
                    earns and receives monthly management and operating fees
                    from certain joint venture partners after the properties are
                    completed and placed into production.

          H.        Income Taxes - Everflow is not a tax-paying entity and the
                    net taxable income or loss, other than the taxable income or
                    loss allocable to EEI, which is a C corporation owned by
                    Everflow, will be allocated directly to its respective
                    partners. The Company is not able to determine the net
                    difference between the tax bases and the reported amounts of
                    Everflow's assets and liabilities due to separate tax
                    elections that were made by owners of the working interests
                    and limited partnership interests that comprised Programs.

                    EEI and its subsidiaries account for income taxes under SFAS
                    No. 109, "Accounting for Income Taxes." Income taxes are
                    provided for all items (as they relate to EEI and its
                    subsidiaries) in the Consolidated Statement of Income
                    regardless of the period when such items are reported for
                    income tax purposes. SFAS No. 109 provides that deferred tax
                    assets and liabilities be recognized for temporary
                    differences between the financial reporting basis and tax
                    basis of certain of EEI's and its subsidiaries' assets and
                    liabilities. In addition, SFAS No. 109 requires that
                    deferred tax assets and liabilities be measured using
                    enacted tax rates expected to apply to taxable income in the
                    years in which the temporary differences are expected to be
                    recovered or settled. The impact on deferred taxes of
                    changes in tax rates and laws, if any, is reflected in the
                    financial statements in the period of enactment. In some
                    situations, SFAS No. 109 permits the recognition of expected
                    benefits of utilizing net operating loss and tax credit
                    carryforwards.

          I.        Allocation of Income and Per Unit Data - Under the terms of
                    the limited partnership agreement, initially, 99% of
                    revenues and costs were allocated to the unitholders (the
                    limited partners) and 1% of revenues and costs were
                    allocated to the general partner. The allocation changes as
                    unitholders elect to exercise the repurchase right (see Note
                    4).

                    Earnings and distributions per limited partner Unit have
                    been computed based on the weighted average number of Units
                    outstanding during the year for each year presented. Average
                    outstanding Units for earnings and distributions per Unit
                    calculations amount to 5,829,918, 5,991,928 and 6,133,865 in
                    2001, 2000 and 1999, respectively.

                                      F-11


<PAGE>
                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


NOTE 1.   ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
          (CONTINUED)

          J.        New Accounting Standards - In June 1998, SFAS No. 133,
                    "Accounting for Derivative Instruments and Hedging
                    Activities," was issued. SFAS No. 133 establishes accounting
                    and reporting standards for derivative instruments and
                    hedging activities. SFAS No. 133, as amended by SFAS No.
                    137, is effective for all fiscal quarters of all fiscal
                    years beginning after June 15, 2000. In June 2001, the
                    Financial Accounting Standards Board ("FASB") issued SFAS
                    No. 141, "Business Combinations." SFAS No. 141 requires the
                    purchase method of accounting for business combinations
                    initiated after June 30, 2001 and eliminates the
                    pooling-of-interest method and further clarifies the
                    criteria to recognize intangible assets separately from
                    goodwill. The adoption of SFAS Nos. 133 and 141 had no
                    material effect on the Company's financial statements.

                    In June 2001, FASB issued SFAS No. 142, "Goodwill and Other
                    Intangible Assets." Under SFAS No. 142, goodwill and
                    intangible assets deemed to have indefinite lives will no
                    longer be amortized but will be subject to periodic
                    impairment tests. Other intangible assets will continue to
                    be amortized over their useful lives. SFAS No. 142 is
                    effective for fiscal years beginning after December 15,
                    2001. In June 2001, FASB issued SFAS No. 143, "Accounting
                    for Asset Retirement Obligations," which is effective the
                    first quarter of fiscal year 2003. SFAS 143 addresses
                    financial accounting and reporting for obligations
                    associated with the retirement of long-lived assets and the
                    associated asset retirement cost. In August 2001, FASB
                    issued SFAS No. 144, "Accounting for the Impairment or
                    Disposal of Long-lived Assets," which is effective the first
                    quarter of fiscal year 2002. SFAS No. 144 modifies and
                    expands the financial accounting and reporting for the
                    impairment or disposal of long-lived assets other than
                    goodwill. The Company is still evaluating the impact of
                    these new standards, but at this time does not believe their
                    adoption will have a significant impact on its financial
                    position and results of operations.

NOTE 2.   SHORT-TERM INVESTMENTS

          Short-term investments consist principally of marketable corporate
          debt securities which are classified as trading. The fair values of
          the investments approximate cost.

NOTE 3.   CREDIT FACILITIES AND LONG-TERM DEBT

          In August 2001, the Company entered into an agreement that modified
          (extended) its prior credit agreement. The agreement provides for a
          revolving line of credit in the amount of $4,000,000, all of which is
          available. The revolving line of credit provides for interest payable
          quarterly at LIBOR plus 150 basis points with the principal due at
          maturity, May 31, 2003. The Company anticipates renewing the facility
          every other year to minimize debt origination, carrying and interest
          costs associated with long-term bank commitments. Borrowings under the
          facility are unsecured; however, the Company has agreed, if requested
          by the bank, to execute any supplements to the agreement including
          security and mortgage agreements on the Company's assets. The
          agreement contains restrictive covenants requiring the Company to
          maintain the following: (i) loan balance not to exceed the borrowing
          base of $4,000,000; (ii) tangible net worth of at least $40,000,000;
          and (iii) a total debt to tangible net worth ratio of not more than
          0.5 to 1.0. In addition, there are restrictions on mergers, sales and
          acquisitions, the incurrence of additional debt and the pledge or
          mortgage of the Company's assets.



                                      F-12

<PAGE>
                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



NOTE 3.   CREDIT FACILITIES AND LONG-TERM DEBT (CONTINUED)

          There were no borrowings outstanding on revolving credit facilities at
          December 31, 2001 and 2000. The following schedule reflects activity
          under the Company's revolving credit facilities for the years ended
          December 31, 2001, 2000 and 1999. The average amount outstanding under
          the facility was calculated using daily balances and a 365 day period.
          The weighted average interest rates were calculated by dividing the
          interest expense for the year for such borrowings by the average
          amounts outstanding during the period.
<TABLE>
<CAPTION>

                                                                                            Weighted
                                                    Maximum             Average              Average
                                                     Amount             Amount             Interest
                                                  Outstanding         Outstanding             Rate
                                                  -----------         -----------             ----
                    <S>                            <C>                 <C>                   <C>
                    Year Ended December 31:
                           2001                    $       -           $       -                -

                           2000                    $       -           $       -                -

                           1999                    $2,700,000          $ 757,808             6.8%
</TABLE>



          The Company purchased a building and funded its cost, including
          improvements, in part, through mortgage notes. The notes have an
          aggregate balance of $512,014 and $637,822 at December 31, 2001 and
          2000, respectively, and at December 31, 2001 bear interest at fixed
          (with options to adjust or convert to variable in certain subsequent
          years) rates ranging from 5.47% - 8.06% and a weighted average rate of
          6.51%. The notes at December 31, 2001 require aggregate payments of
          principal and interest of $7,175 per month. Maturities on the notes
          are expected to be as follows: 2002 - $53,900; 2003 - $57,500; 2004 -
          $61,400; 2005 - $65,600; 2006 - $68,100; thereafter - $205,514.

          The Company is exposed to market risk from changes in interest rates
          since it, at times, funds its operations through long-term and
          short-term borrowings. The Company's primary interest rate risk
          exposure results from floating rate debt with respect to the Company's
          revolving credit. At December 31, 2001, none of the Company's total
          long-term debt consisted of floating rate debt.

NOTE      4. PARTNERS' EQUITY

          Units represent limited partnership interests in Everflow. The Units
          are transferable subject only to the approval of any transfer by
          Everflow Management Limited, LLC and to the laws governing the
          transfer of securities. The Units are not listed for trading on any
          securities exchange nor are they quoted in the automated quotation
          system of a registered securities association. However, unitholders
          have an opportunity to require Everflow to repurchase their Units
          pursuant to the repurchase right.

          Under the terms of the limited partnership agreement, initially, 99%
          of revenues and costs are allocated to the unitholders (the limited
          partners) and 1% of revenues and costs are allocated to the general
          partner. Such allocation has changed and will change in the future due
          to unitholders electing to exercise the repurchase right.


                                      F-13

<PAGE>
                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)




NOTE 4.   PARTNERS' EQUITY (CONTINUED)

          The partnership agreement provides that Everflow will repurchase for
          cash up to 10% of the then outstanding Units, to the extent
          unitholders offer Units to Everflow for repurchase pursuant to the
          repurchase right. The repurchase right entitles any unitholder,
          between May 1 and June 30 of each year, to notify Everflow that he
          elects to exercise the repurchase right and have Everflow acquire
          certain or all of his Units. The price to be paid for any such Units
          is calculated based upon the audited financial statements of the
          Company as of December 31 of the year prior to the year in which the
          repurchase right is to be effective and independently prepared reserve
          reports. The price per Unit equals 66% of the adjusted book value of
          the Company allocable to the Units, divided by the number of Units
          outstanding at the beginning of the year in which the applicable
          repurchase right is to be effective less all interim cash
          distributions received by a unitholder. The adjusted book value is
          calculated by adding partners' equity, the standardized measure of
          discounted future net cash flows and the tax effect included in the
          standardized measure and subtracting from that sum the carrying value
          of oil and gas properties (net of undeveloped lease costs). If more
          than 10% of the then outstanding Units are tendered during any period
          during which the repurchase right is to be effective, the investors'
          Units tendered shall be prorated for purposes of calculating the
          actual number of Units to be acquired during any such period. The
          price associated with the repurchase right, based upon the December
          31, 2001 calculation, is estimated to be $5.66 per Unit, net of the
          distributions ($.50 per Unit in total) expected to be made in January
          and April 2002.

          Units repurchased pursuant to the repurchase right, for each of the
          four years in the period ended December 31, 2001, are as follows:

<TABLE>
<CAPTION>


                                               Per Unit
                         ---------------------------------------------------------
                         Calculated                                                                       Units
                          Price for                      Less                                          Outstanding
                         Repurchase     Premium        Interim            Net          # of Units       Following
             Year          Right        Offered     Distributions      Price Paid      Repurchased      Repurchase
           -------       ----------    ---------    ---------------   ------------    -------------     ----------

            <S>           <C>          <C>            <C>           <C>              <C>              <C>
             1998         $ 5.24         $ --          $  .25           $ 4.99           35,114         6,172,537

             1999         $ 6.16         $ --          $ .375           $ 5.79           77,344         6,095,193

             2000         $ 6.73         $ --          $ .625           $ 6.11          206,531         5,888,662

             2001         $10.35         $ --          $ .625           $ 9.73          117,488         5,771,174

</TABLE>

                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


NOTE 5.   PROVISION FOR INCOME TAXES

          As referred to in Note 1, EEI and its subsidiaries account for current
          and deferred income taxes under the provisions of SFAS No. 109. The
          deferred taxes are the result of temporary differences arising from
          differences in financial reporting and tax reporting methods for EEI's
          proved properties.






                                      F-14
<PAGE>
                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



NOTE 5.   PROVISION FOR INCOME TAXES (CONTINUED)

          A reconciliation between taxes computed at the Federal statutory rate
          and the effective tax rate in the statements of income follows:
<TABLE>
<CAPTION>

                                                                                Year Ended December 31,
                                                 ------------------------------------------------------------------------------
                                                            2001                         2000                    1999
                                                 ------------------------    -----------------------   ------------------------
                                                    Amount          %           Amount          %         Amount          %
                                                 -----------    ---------    -----------    --------    -----------    --------
         <S>                                     <C>               <C>       <C>             <C>        <C>             <C>
          Provision based on the
           statutory rate (for taxable
           income up to $10,000,000)             $ 2,666,000         34.0    $ 2,921,000        34.0    $ 1,825,000        34.0

          Tax effect of:
           Non-taxable status of the
             Programs and Everflow                (2,654,000)       (33.8)    (2,965,000)      (34.5)    (1,866,000)      (34.8)
           Excess statutory depletion                (70,000)        (0.9)       (83,000)       (1.0)       (72,000)       (1.3)
           Graduated tax rates, state
             income tax and other - net               58,000          0.7        127,000         1.5         35,000         0.6
                                                 -----------    ---------    -----------    --------    -----------    --------

           Total                                 $      --           --      $      --          --      $   (78,000)       (1.5)
                                                 ===========    =========    ===========    ========    ===========    ========
</TABLE>


          EEI has percentage depletion deduction carryforwards for tax purposes
          of approximately $2,160,000. These carryforwards can be carried
          forward indefinitely. For financial reporting purposes, the deferred
          tax liability at December 31, 2001 and 2000 has been reduced by
          approximately $661,000 and $730,000, respectively, for the tax effect
          of carryforwards.

NOTE 6.   RETIREMENT PLAN

          The Company has a defined contribution plan pursuant to Section 401(k)
          of the Internal Revenue Code for all employees who have reached the
          age of 21 and completed one year of service. Certain contributions to
          the plan are at the discretion of EMC's Board of Directors. The
          Company matched employees' contributions to the 401(K) Retirement
          Savings Plan to the extent of 50% of the first 6% of a participant's
          salary reduction in 1999. Beginning in 2000, the Company matched
          employees' contributions to the 401(K) Retirement Savings Plan to the
          extent of 100% of the first 6% of a participant's salary reduction.
          The amounts attributable to the Company's matching contribution vest
          immediately. The Company made contributions of $63,275, $52,683 and
          $38,879 for the years ended December 31, 2001, 2000 and 1999,
          respectively.





                                      F-15
<PAGE>
                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


NOTE 7.   RELATED PARTY TRANSACTIONS

          Since 1989, EEI provided certain employees with an opportunity to
          receive assignments of certain overriding royalty interests which were
          created at the time EEI generated certain oil and gas leases. Certain
          employees of the Company have been given the option of having a
          portion of their compensation in the form of an assignment in certain
          of such overriding royalty interests. Those employees who elect to
          receive a portion of their compensation in this form receive an
          assignment of a pro rata portion of each of the overriding royalty
          interests selected. During the calendar years ended December 31, 2001,
          2000 and 1999, approximately $140,000, $140,000 and $117,000,
          respectively, was distributed to such employees from such overriding
          royalty interests.

          The Company's Officers, Directors, Affiliates and certain employees
          have frequently participated, and will likely participate in the
          future, as working interest owners in wells in which the Company has
          an interest. Frequently, the Company has loaned the funds necessary to
          participate in the drilling and development of such wells. Such loans
          currently accrue interest at LIBOR plus 150 basis points. Such
          receivables are expected to be paid from production revenues
          attributable to such interests or through joint interest assessments.

NOTE 8.   BUSINESS SEGMENTS, RISKS AND MAJOR CUSTOMERS

          The Company operates exclusively in the United States, almost entirely
          in Ohio and Pennsylvania, in the exploration, development and
          production of oil and gas.

          The Company operates in an environment with many financial risks,
          including, but not limited to, the ability to acquire additional
          economically recoverable oil and gas reserves, the inherent risks of
          the search for, development of and production of oil and gas, the
          ability to sell oil and gas at prices which will provide attractive
          rates of return, the volatility and seasonality of oil and gas
          production and prices, and the highly competitive and, at times,
          seasonal nature of the industry and worldwide economic conditions. The
          Company's ability to expand its reserve base and diversify its
          operations is also dependent upon the Company's ability to obtain the
          necessary capital through operating cash flow, additional borrowings
          or additional equity funds. Various federal, state and governmental
          agencies are considering, and some have adopted, laws and regulations
          regarding environmental protection which could adversely affect the
          proposed business activities of the Company. The Company cannot
          predict what effect, if any, current and future regulations may have
          on the operations of the Company.

          Management of the Company continually evaluates whether the Company
          can develop oil and gas properties at historical levels given current
          industry and market conditions. If the Company is unable to do so, it
          could be determined that it is in the best interests of the Company
          and its unitholders to reorganize, liquidate or sell the Company.
          However, management cannot predict whether any sale transaction will
          be a viable alternative for the Company in the immediate future.




                                      F-16
<PAGE>
                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)




NOTE 8.   BUSINESS SEGMENTS, RISKS AND MAJOR CUSTOMERS (CONTINUED)

          Gas sales accounted for 89%, 84% and 89% of total oil and gas sales in
          2001, 2000 and 1999, respectively. Approximate percentages of total
          oil and gas sales from significant purchasers for the years ended
          December 31, 2001, 2000 and 1999, respectively, were as follows:

<TABLE>
<CAPTION>

                                                           Customer                   2001               2000           1999
                                                           --------                   ----               ----           ----

                     <S>                                                            <C>                 <C>           <C>
                        Dominion Field Services, Inc., its affiliates and its
                          predecessors ("Dominion")                                    45 %               53 %           67 %
                        Ergon Oil Purchasing, Inc. ("Ergon Oil")                       11                 16             11
                        Interstate Gas Supply, Inc. ("IGS")                            25                 11              -
                                                                                      ---                ---            ---

                                                                                      81  %              80  %           78  %
                                                                                      ===                ===            ===
</TABLE>


          The Company expects that Dominion, Ergon Oil and IGS will be the only
          major customers in 2002.

          In 2001 and over the past ten years, the Company had been selling a
          significant portion of its natural gas pursuant to Intermediate Term
          Adjustable Price Gas Purchase Agreements with Dominion.

          The Company's last remaining agreement terminated during 2001 and was
          replaced by short-term contracts, which obligate Dominion to purchase,
          and the Company to sell and deliver, certain natural gas production
          from the Company's wells throughout the contract periods. A summary of
          certain pricing provisions included in gas purchase contracts with
          Dominion follows:

          Production Period November 2001 through March 2002 (Dominion)

          The first 40,000 MCF per month is priced at $3.51 per MCF. The next
          50,000 MCF per month is priced at $4.73 per MCF. The next 50,000 MCF
          per month is priced at $5.35 per MCF. All gas in excess of 140,000 MCF
          per month is priced at the NYMEX settled price plus $.10 up to the
          first 250,000 MCF in the aggregate during the period. All gas in
          excess of the above volumes is priced at the NYMEX settled price plus
          $.45.

          Production Period April 2002 through October 2002 (Dominion)

          The first 50,000 MCF per month is priced at $4.73 per MCF. The next
          50,000 MCF per month is priced at $5.35 per MCF. The next 20,000 MCF
          per month is priced at $3.35 per MCF. In the event the 250,000 MCF in
          the November 2001 through March 2002 period is not met, any remaining
          balance is priced at the NYMEX settled price plus $.10 during the
          period. All gas in excess of the above volumes is priced at the NYMEX
          settled price plus $.45.


                                      F-17
<PAGE>

                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


NOTE 8.   BUSINESS SEGMENTS, RISKS AND MAJOR CUSTOMERS (CONTINUED)

          Production Period November 2002 through October 2003 (Dominion)

          The first 20,000 MCF per month is priced at $3.35 per MCF. The next
          20,000 MCF per month is priced at $4.00. The next 20,000 MCF per month
          is priced at $4.10. All gas in excess of the above volumes is priced
          at NYMEX settled price plus $.45.

          Production Period November 2003 through March 2004 (Dominion)

          The first 20,000 MCF per month is priced at $4.05 per MCF. Gas in
          excess of 20,000 MCF per month has not been committed.

          The Company also has short-term contracts with IGS, which obligate IGS
          to purchase, and the Company to sell and deliver, certain quantities
          of natural gas production on a monthly basis throughout the contract
          periods. A summary of certain pricing provisions included in the gas
          purchase contracts with IGS follows:

          Production Period November 2001 through October 2002 (IGS)

          The first 50,000 MCF per month is priced at $4.56 per MCF. All gas in
          excess of 50,000 MCF per month is priced at NYMEX settled price plus
          $.42.

          Production Period April 2002 through October 2002 and April 2003
          through October 2003 (IGS)

          The first 20,000 MCF per month is priced at $3.19 per MCF. All gas in
          excess of 20,000 MCF per month is priced at the NYMEX settled price
          plus $.27.

          Production Period November 2002 through March 2003 (IGS)

          The first 20,000 MCF per month is priced at $3.19 per MCF. The next
          20,000 MCF per month is priced at $4.01 per MCF. All gas in excess of
          the above volumes is priced at the NYMEX settled price plus $.57.

          Production Period November 2003 through March 2004 (IGS)

          The first 20,000 MCF per month is priced at $4.10 per MCF. All gas in
          excess of 20,000 MCF per month is priced at the NYMEX settled price
          plus $.57.

          As detailed above, the price paid for natural gas purchased by
          Dominion and IGS varies based on quantities locked in by the Company
          from time to time. As of December 31, 2001, natural gas purchased by
          Dominion covers production from approximately 420 gross wells, while
          natural gas purchased by IGS covers production from approximately 190
          gross wells.


                                      F-18

<PAGE>
                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)




NOTE 9.   COMMITMENTS AND CONTINGENCIES

          Everflow paid a dividend in January 2002 of $.25 per Unit. The
          distribution amounted to approximately $1,460,000.

          The Company is the general partner in certain oil and gas
          partnerships. As general partner, the Company shares in unlimited
          liability to third parties with respect to the operations of the
          partnerships and may be liable to limited partners for losses
          attributable to breach of fiduciary obligations.

NOTE 10.  SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

          The following is a summary of selected quarterly financial data for
          the years ended December 31, 2001 and 2000:
<TABLE>
<CAPTION>

                                                           Quarters Ended
                                         ---------------------------------------------------------------
                                          March 31         June 30        September 30       December 31
                                         ----------       ---------       -------------     ------------
<S>                                        <C>              <C>              <C>              <C>
            2001
            ----
              Revenues                     $4,877,102       $3,773,349       $3,910,598       $3,700,171
              Income from operations        2,180,895        1,808,311        1,848,477        1,826,417
              Net income                    2,243,774        1,869,935        1,876,055        1,852,398
              Net income per unit                 .38              .31              .32              .32


<CAPTION>

                                                           Quarters Ended
                                         ---------------------------------------------------------------
                                          March 31         June 30         September 30     December 31
                                         ----------       ---------       -------------     ------------
<S>                                        <C>              <C>              <C>              <C>
            2000
            ----
              Revenues                   $4,584,831       $3,328,253       $3,313,751       $5,694,304
              Income from operations      1,782,528        1,403,796        1,241,006        3,892,571
              Net income                  1,826,116        1,474,780        1,301,405        3,988,456
              Net income per unit               .30              .24              .22              .67
</TABLE>




          Quarterly operating results are not necessarily representative of
          operations for a full year for various reasons, including the
          volatility and seasonality of oil and gas production and prices, the
          highly competitive and, at times, seasonal nature of the oil and gas
          industry and worldwide economic conditions.









                                      F-19

<PAGE>

                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NOTE 11.  SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES
            (UNAUDITED)

          The following supplemental unaudited oil and gas information is
          required by SFAS No. 69, "Disclosures About Oil and Gas Producing
          Activities."

          The tables on the following pages set forth pertinent data with
          respect to the Company's oil and gas properties, all of which are
          located within the continental United States.

<TABLE>
<CAPTION>
                                              CAPITALIZED COSTS RELATING TO OIL AND GAS
                                                        PRODUCING ACTIVITIES


                                                                        December 31,
                                                   ------------------------------------------------------
                                                        2001               2000              1999
                                                        ----               ----              ----
<S>                                                 <C>                <C>                <C>
            Proved oil and gas properties           $114,964,451       $112,341,851       $110,483,039
            Pipeline and support equipment               504,222            504,222            507,472
                                                    ------------       ------------       ------------
                                                     115,468,673        112,846,073        110,990,511
            Accumulated depreciation, depletion,
              amortization and write down             72,365,538         68,469,693         64,241,134
                                                    ------------       ------------       ------------

            Net capitalized costs                   $ 43,103,135       $ 44,376,380       $ 46,749,377
                                                    ============       ============       ============
<CAPTION>

                                         COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES


                                                                          December 31,
                                                     ------------------------------------------------------
                                                            2001                 2000               1999
                                                            ----                 ----               -----
<S>                                                   <C>                 <C>                 <C>
            Property acquisition costs                $    234,786        $    175,875        $    292,852
            Development costs, including
              prepayments                                3,135,374           2,333,387           2,614,116
</TABLE>


          In 2001, 2000 and 1999, development costs include the purchase of
          approximately $309,000, $-0- and $1,452,000, respectively, of
          producing oil and gas properties.
















                                      F-20











<PAGE>
                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)




NOTE 11.  SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING
          ACTIVITIES (UNAUDITED) (CONTINUED)

<TABLE>
<CAPTION>

                                                RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

                                                                                          December 31,
                                                                    ---------------------------------------------------
                                                                          2001               2000              1999
                                                                          ----               ----              ----

<S>                                                                  <C>                <C>                <C>
            Oil and gas sales                                        $ 15,805,040       $ 16,490,904       $ 14,639,109
            Production costs                                           (2,419,260)        (2,244,926)        (2,638,217)
            Depreciation, depletion and
              amortization                                             (4,449,545)        (4,510,787)        (4,762,466)
            Abandonment and write down of
              oil and gas properties                                     (200,000)          (400,000)          (648,742)
                                                                     ------------       ------------       ------------
                                                                        8,736,235          9,335,191          6,589,684

            Income tax expense                                            100,000            100,000            115,000
                                                                     ------------       ------------       ------------

            Results of operations for oil and gas
              producing activities (excluding
              corporate overhead and financing
              costs)                                                 $  8,636,235       $  9,235,191       $  6,474,684
                                                                     ============       ============       ============
</TABLE>

          Income tax expense was computed using statutory tax rates and reflects
          permanent differences that are reflected in the Company's consolidated
          income tax expense for the year.






















                                      F-21

<PAGE>
                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)




NOTE 11.  SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING
          ACTIVITIES (UNAUDITED) (CONTINUED)

               ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES

<TABLE>
<CAPTION>

                                                                                         Oil                    Gas
                                                                                       (BBLS)                  (MCF)
                                                                                    -----------             -----------

<S>                                                                                  <C>                  <C>
            Balance, January 1, 1999                                                    935,000              52,903,000
              Extensions, discoveries and other
                additions                                                                38,000               4,018,000
              Production                                                                (97,000)             (4,245,000)
              Revision of previous estimates                                             (1,000)             (1,170,000)
                                                                                    -----------             -----------

            Balance, December 31, 1999                                                  875,000              51,506,000
              Extensions, discoveries and other
                additions                                                                 3,000               1,195,000
              Production                                                                (92,000)             (4,196,000)
              Revision of previous estimates                                            128,000                  29,000
                                                                                    -----------             -----------

            Balance, December 31, 2000                                                  914,000              48,534,000
              Extensions, discoveries and other
                additions                                                                35,000               1,940,000
              Production                                                                (76,000)             (3,583,000)
              Revision of previous estimates                                           (154,000)             (4,966,000)
                                                                                    -----------             -----------

            Balance, December 31, 2001                                                  719,000              41,925,000
                                                                                    ===========             ===========

            PROVED DEVELOPED RESERVES:
              December 31, 1998                                                         935,000              52,903,000
              December 31, 1999                                                         875,000              51,506,000
              December 31, 2000                                                         914,000              48,534,000
              December 31, 2001                                                         719,000              41,925,000
</TABLE>


          The Company has not determined proved reserves associated with its
          proved undeveloped acreage. At December 31, 2001 and 2000, the Company
          had 700 and 780 net proved undeveloped acres, respectively. The
          carrying cost of the proved undeveloped acreage that is included in
          proved properties amounted to $528,208 and $682,206 at December 31,
          2001 and 2000, respectively.


                                      F-22
<PAGE>
                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


NOTE 11.  SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING
          ACTIVITIES (UNAUDITED) (CONTINUED)




                    STANDARDIZED MEASURE OF DISCOUNTED FUTURE
                                 NET CASH FLOWS

<TABLE>
<CAPTION>

                                                                          December 31,
                                                          --------------------------------------------
                                                              2001            2000              1999
                                                              ----            ----              ----
                                                                                (Thousands of Dollars)
<S>                                                        <C>              <C>              <C>
            Future cash inflows from sales of oil
              and gas                                      $138,032         $248,711         $166,772
            Future production and development
              costs                                          57,159           81,641           64,142
            Future income tax expense                         1,675            3,971            2,405
                                                           --------         --------         --------

            Future net cash flows                            79,198          163,099          100,225
            Effect of discounting future net cash
              flows at 10% per annum                         34,104           81,125           46,532
                                                           --------         --------         --------

            Standardized measure of discounted
              future net cash flows                        $ 45,094         $ 81,974         $ 53,693
                                                           ========         ========         ========






<CAPTION>

                     CHANGES IN THE STANDARDIZED MEASURE OF
                        DISCOUNTED FUTURE NET CASH FLOWS


                                                                      Year Ended December 31,
                                                          -------------------------------------------
                                                              2001            2000              1999
                                                              ----            ----              ----
                                                                                 (Thousands of Dollars)

<S>                                                        <C>              <C>              <C>
            Balance, beginning of year                     $ 81,974         $ 53,693         $ 51,479
            Extensions, discoveries and other
              additions                                       2,814            2,141            4,486
            Development costs incurred                          313              245              298
            Revision of previous estimates                   (5,833)           1,133           (2,240)
            Sales of oil and gas, net of production
              costs                                         (13,386)         (14,246)         (12,001)
            Net change in income taxes                        1,042             (708)             (55)
            Net changes in prices and production
              costs                                         (30,076)          28,769            3,304
            Accretion of discount                             8,197            5,369            5,148
            Other                                                49            5,578            3,274
                                                           --------         --------         --------

            Balance, end of year                           $ 45,094         $ 81,974         $ 53,693
                                                           ========         ========         ========

</TABLE>








                                      F-23

<PAGE>
                        EVERFLOW EASTERN PARTNERS, L. P.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)




NOTE 11.  SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING
          ACTIVITIES (UNAUDITED) (CONTINUED)

          The estimated future cash flows are determined based on year-end
          prices for crude oil, current allowable prices (reduced for periods
          beyond the contract period to year-end market prices) applicable to
          expected natural gas production, estimated production of proved crude
          oil and natural gas reserves, estimated future production and
          development costs of reserves, based on current economic conditions,
          and the estimated future income tax expense, based on year-end
          statutory tax rates (with consideration of future tax rates already
          legislated) to be incurred on pretax net cash flows less the tax basis
          of the properties involved. Such cash flows are then discounted using
          a 10% rate.

          The methodology and assumptions used in calculating the standardized
          measure are those required by SFAS No. 69. It is not intended to be
          representative of the fair market value of the Company's proved
          reserves. The valuation of revenues and costs does not necessarily
          reflect the amounts to be received or expended by the Company. In
          addition to the valuations used, numerous other factors are considered
          in evaluating known and prospective oil and gas reserves.




















                                      F-24